Method and System for Removing Hydrogen Sulfide from Sour Oil and Sour Water

ABSTRACT

Embodiments of the present invention are generally related to a system and method to remove hydrogen sulfide from sour water and sour oil. Particularly, hydrogen sulfide is removed from sour water and sour oil without the need for special chemicals, such as catalyst chemicals, scavenger chemicals, hydrocarbon sources, or a large-scale facility. The system and method in the present invention is particularly useful in exploratory oil and gas fields, where large facilities to remove hydrogen sulfide may be inaccessible. The present invention addresses the need for safe and cost-effective transport of the deadly neurotoxin. Particular embodiments involve a system and method that can be executed both on a small and large scale to sweeten sour water and sour oil.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.17/141,214, filed Jan. 4, 2021 (now U.S. Pat. No. 11,440,815, issuedSep. 13, 2022), which is a continuation-in-part of U.S. patentapplication Ser. No. 15/945,277, filed Apr. 4, 2018 (now U.S. Pat. No.10,882,762, issued Jan. 5, 2021), which is a continuation of U.S. patentapplication Ser. No. 15/646,153, filed Jul. 11, 2017 (now U.S. Pat. No.9,938,163, issued Apr. 10, 2018), which is a continuation of U.S. patentapplication Ser. No. 15/180,426, filed Jun. 13, 2016 (now U.S. Pat. No.9,708,196, issued Jul. 18, 2017), which is a continuation-in-part ofU.S. patent application Ser. No. 14/709,286, filed May 11, 2015 (nowU.S. Pat. No. 9,364,773, issued Jun. 14, 2016), which is acontinuation-in-part of U.S. patent application Ser. No. 14/185,006,filed Feb. 20, 2014 (now U.S. Pat. No. 9,028,679, issued May 12, 2015),which claims the benefit of U.S. Provisional Patent Application61/768,029, filed on Feb. 22, 2013, the entire contents of which areeach incorporated herein by reference in their entirety for allpurposes.

FIELD OF THE INVENTION

Embodiments of the present invention are generally related to a systemand method to remove hydrogen sulfide from sour water and sour oil.Particularly, hydrogen sulfide is removed from sour water and sour oilwithout the need for special chemicals, such as catalyst chemicals,scavenger chemicals, hydrocarbon sources, or a large-scale facility. Thesystem and method in the present invention is particularly useful inexploratory oil and gas fields, where large facilities to removehydrogen sulfide may be inaccessible. The present invention addressesthe need for safe and cost-effective transport of the deadly neurotoxin.Particular embodiments involve a system and method that can be executedboth on a small and large scale to sweeten sour water and sour oil.

BACKGROUND OF THE INVENTION

Exploration of gas fields can involve discovery of wells that containsignificant quantities of hydrogen sulfide and other organic andinorganic sulfur compounds. Oil, natural gas, and water with a highconcentration of sulfur compounds such as hydrogen sulfide and sulfurdioxide are referred to as “sour.” Hydrogen sulfide is a colorless,toxic, flammable gas that is responsible for the foul odor of rotteneggs. It often results when bacteria break down organic matter in theabsence of oxygen, such as in swamps, and sewers alongside the processof anaerobic digestion. It also occurs in volcanic gases, natural gasand some well waters. Sour oil and sour water are not only undesirableas sour products are economically useful, but they can also be extremelytoxic and deadly because high levels of sulfur and sulfur byproducts.For example, hydrogen sulfide is a highly toxic and extremely deadlygas. The industry considers oil or water containing 100 parts permillion (“ppm”) (0.01%) sulfur sour oil and sour water. Although this isthe minimum level, oil wells and water can contain higher amounts. Oiland water can contain hydrogen sulfide up to 300,000 ppm (30%) at theimmediate gas/liquid interphase, the vapor space in a tank or container,and the atmosphere surrounding a spill. At higher concentrations,hydrogen sulfide is toxic and deadly.

As used herein, the term “sour oil” refers to oil containing levels ofhydrogen sulfide in an amount greater than 100 ppm (0.01%). Sour oil canalso mean oil containing 0.5% or more sulfur by weight. The term “sourwater” refers to water containing hydrogen sulfide in an amount greaterthan 100 ppm (0.01%). The terms “sweet,” “sweetened,” and/or“sweetening” mean a product that has low levels of hydrogen sulfide, hashad hydrogen sulfide removed, or the process of removing hydrogensulfide. The term “stripping” means removing hydrogen sulfide from waterand/or oil. The terms “acceptable limits” or “acceptable amounts” or“acceptable levels” refer to the maximum amount of hydrogen sulfideallowed according to any of the pertinent regulations. For example, theEnvironmental Protection Agency (“EPA”) has certain regulationsregarding the concentration of hydrogen sulfide that may be releasedinto the environment. Furthermore, the Occupational Safety and HealthAdministration (“OSHA”) provides certain regulations on the amount ofhydrogen sulfide one may be exposed to without being considered a healthhazard. There may be other regulations that apply, such as stateregulations. The terms “acceptable limits” or “acceptable amounts” or“acceptable levels” can also refer to the maximum amount of hydrogensulfide allowed in oil and/or water for a facility to accept thematerials.

Exploratory and developmental wells with high concentrations of hydrogensulfide, far away from hydrogen sulfide removal facilities present aproblem of transporting the sour water and sour oil. Both liquids mustbe transported by truck, sometimes long distances over public andprivate roads. In most cases, sour water, which is dangerous totransport, will also not be accepted by most re-injection facilities ifit contains more than a trace amount of hydrogen sulfide.

Similarly, sour oil, which is also dangerous to transport, will not beaccepted by most refineries or pipeline hubs if it contains more than atrace of hydrogen sulfide. If one finds a facility willing to acceptliquids with a high concentration of hydrogen sulfide, odds are they arehundreds of miles away from the exploratory well. A truck accident or asimple leak could endanger the transportation crew, as well as thepublic.

Raw or unprocessed crude oil is not generally useful in industrialapplications, although “light, sweet” (low viscosity, low sulfur) crudeoil has been used directly as a burner fuel to produce steam for thepropulsion of seagoing vessels. The lighter elements, however, formexplosive vapors in the fuel tanks and are therefore hazardous. Instead,the hundreds of different hydrocarbon molecules in crude oil areseparated in a refinery into components which can be used as fuels,lubricants, and as feedstocks in petrochemical processes thatmanufacture such products as plastics, detergents, solvents, elastomersand fibers such as nylon and polyesters.

Petroleum fossil fuels are burned in internal combustion engines toprovide power for ships, automobiles, aircraft engines, lawn mowers,chainsaws, and other machines. Different boiling points allow thehydrocarbons to be separated by distillation. Since the lighter liquidproducts are in great demand for use in internal combustion engines, amodern refinery will convert heavy hydrocarbons and lighter gaseouselements into these higher value products.

Oil can be used in a variety of ways because it contains hydrocarbons ofvarying molecular masses, forms and lengths such as paraffins,aromatics, naphthenes (or cycloalkanes), alkenes, dienes, and alkynes.While the molecules in crude oil include different atoms such as sulfurand nitrogen, the hydrocarbons are the most common form of molecules,which are molecules of varying lengths and complexity made of hydrogenand carbon atoms, and a small number of oxygen atoms. The differences inthe structure of these molecules account for their varying physical andchemical properties, and it is this variety that makes crude oil usefulin a broad range of several applications.

Once separated and purified of any contaminants and impurities, the fuelor lubricant can be sold without further processing. Smaller moleculessuch as isobutane and propylene or butylenes can be recombined to meetspecific octane requirements by processes such as alkylation, or morecommonly, dimerization. The octane grade of gasoline can also beimproved by catalytic reforming, which involves removing hydrogen fromhydrocarbons producing compounds with higher octane ratings such asaromatics. Intermediate products such as fuel oils can even bereprocessed to break a heavy, long-chained oil into a lightershort-chained one, by various forms of cracking such as fluid catalyticcracking, thermal cracking, and hydrocracking. The final step ingasoline production is the blending of fuels with different octaneratings, vapor pressures, and other properties to meet productspecifications. Another method for reprocessing and upgrading theseintermediate products (residual oils) uses a devolatilization process toseparate usable oil from the waste asphaltene material.

Oil refineries are large scale plants, processing about a hundredthousand to several hundred thousand barrels of crude oil a day. Becauseof the high capacity, many of the units operate continuously, as opposedto processing in batches, at steady state or nearly steady state formonths to years. The high capacity also makes process optimization andadvanced process control very desirable.

Many steps may be involved in the refining of crude oil to producedesired products. At least two steps which are usually involved inrefining of crude oil are fractional distillation and catalyticcracking. Typically, a crude oil feed is first provided to a crudetower. The crude oil will have been preheated and/or heat is provided tothe crude tower by heating fluids such as steam. Lighter components ofthe crude oil are removed from upper portions of the crude tower whileheavier components are removed from lower portions of the crude tower.

The heavy fraction, which is generally referred to as gas oil, istypically provided to a catalytic cracking unit which is generallyreferred to as the gas oil cracker. The gas oil is cracked to producelighter, more valuable components in the catalytic cracking unit.

In the past, it has been common to dispose of components of the crudeoil which are heavier than the gas oil and which were considered verylow value products. However, as it has become necessary to processheavier crudes, it has become more economically desirable to process thecomponents of crude oil which are heavier than gas oil.

It is well known that crude oil may contain components which makeprocessing difficult. As an example, crude oil will generally containmetals such as vanadium, nickel and iron. Such metals will tend toconcentrate in the heavier fractions such as the topped crude andresiduum. The presence of the metals makes further processing of theseheavier fractions difficult since the metals generally act as poisonsfor catalysts employed in processes such as catalytic cracking.

The presence of other components, such as sulfur and nitrogen, is alsoconsidered detrimental to the processability of thehydrocarbon-containing feed stream. Again, sulfur and nitrogen will tendto concentrate in the heavier fractions. Also, the heavier fractions maycontain components (referred to as Ramsbottom carbon residue) which areeasily converted to coke in processes such as catalytic cracking.

Processes used to remove components such as metals, sulfur, nitrogen andRamsbottom carbon residue are often referred to as hydrofining processes(one or all of the described removals may be accomplished in ahydrofining process). Hydrofining processes are used in many refineriesto facilitate the processing of heavy fractions of the crude oil such astopped crude and residuum.

In addition to removing undesired components, a hydrofining process willoften reduce the content of heavies in the feedstock to the hydrofiningprocess. This reduction results in the production of lighter components.Typically, when a hydrofining process is used in the refining of crudeoil, the gas oil components withdrawn from the hydrofining process areprovided to the catalytic cracking unit utilized to crack the gas oilwithdrawn from the crude tower. Heavy fractions from the hydrofiningunit are typically provided to a second catalytic cracker which isgenerally referred to as the heavy oil cracker.

In any process for refining crude oil, including processes wherehydrofining is practiced, it is desirable to produce a product mixhaving the highest possible value. High value is determined bydetermining the amount of each product produced from a barrel of crudeoil. The economic value of each product is then determined and asummation gives the value of the product mix. Even very small increasesin the value of the product mix are extremely desirable because of thevery large volumes of crude oil typically processed in a refinery andalso because of the highly competitive of nature of the crude oilrefining business.

Traditionally, crude oils are first distilled and then processed furtheras separate fractions. Conventionally, distillation is initially carriedout under atmospheric pressure to produce various distillate fractionsincluding naphtha and middle distillates, as well as an atmosphericresiduum or “long” residuum which is then subjected to furtherdistillation under vacuum to produce additional quantities of distillatematerial together with a vacuum residuum or “short” residuum. Thisprocessing scheme which initially separates the components of the crudeaccording to their boiling points has conventionally been regarded assatisfactory because it enables the processing steps which follow thefractionation to be formulated according to the requirements of theindividual fractions which vary not only according to their distillationcharacteristics but also in their chemical compositions.

Crude oil is generally associated with significant quantities ofhydrogen sulfide and contains various other organic and inorganic sulfurcompounds. Natural fossil fuels, such as crude oil and natural gas, thatcontain a substantial concentration of sulfur compounds, such ashydrogen sulfide and sulfur dioxide, are referred to as “sour.” Sulfurcompounds may evolve from fossil fuels over time and the evolution ofthese compounds produces significant environmental and safety issues.Emissions of various sulfur compounds, including hydrogen sulfide andsulfur dioxide are regulated. Due to enhanced regulations andrestrictions, it is desirable to remove sulfur compounds from crude oil.

Exploratory and developmental wells with high concentrations of hydrogensulfide, far away from hydrogen sulfide removal facilities present aproblem of transporting the sour water and sour oil. Both liquids mustbe transported by truck, sometimes long distances over public andprivate roads. In most cases, sour water, which is dangerous totransport, will also not be accepted by most re-injection facilities ifit contains more than a trace amount of hydrogen sulfide.

Similarly, sour oil, which is also dangerous to transport, will not beaccepted by most refineries or pipeline hubs if it contains more than atrace of hydrogen sulfide. If one finds a facility willing to acceptliquids with a high concentration of hydrogen sulfide, it may behundreds of miles away from the exploratory well. A truck accident or asimple leak could endanger the transportation crew, as well as thepublic.

There are other problems downstream in the transportation of sour oil aswell. For example, transport from the exploratory well to a treatmentsite is usually only the first step in the process. The oil typicallyhas an end destination, whether it is another refinery, a distributer,or a consumer. One example can be seen in transportation of oil that isobtained through a fracturing or “fracking” process. Oil extractedthrough the fracking process typically is sweet and contains littlehydrogen sulfide. This oil must be transported from the site to its enddestination. The transportation can be hindered, however, if there is anupstream contamination of sweet oil with hydrogen sulfide of theshipping vessels or oils with different grades are mixed for shipping.

Rail shipment of crude oil has become an option for moving oil out ofhigh production areas with little pipeline access. The shipping industryis adversely affected by having to address the shipping of hydrogensulfide. The solution to rail safety issues are typically unanticipatedcosts, including rail car investments or new safety protocols to addressthe shipping of sour oil.

There is an ever-increasing shortage of naturally-occurring low sulfurcrude oil. With the increasing emphasis on pollution control and theresulting demand for low sulfur content petroleum crude oil, a need forthe economical production of sulfur-reduced crude has arisen.

Besides meeting enhanced regulations and restrictions, removal of sulfurfrom crude oil is desirable for other reasons. Not only does theevolution of sulfur compounds from crude oil produce significantenvironmental and safety issues, these compounds may also attack metalcomponents of the oil well, as well as pipelines and storage tanks anddownstream refinery apparatus. This attack causes corrosion and/orbrittleness of the metal components. Additionally, in a refinery,downstream processes may utilize catalysts which are sensitive to thepresence of sulfur.

In conventional oil refineries, sulfur is generally removed after thecrude oil has been fractionated. Sulfur removal typically comprisesutilization of various desulfurization processes, often requiringextreme operating conditions, and incorporation of expensive equipment,often associated with high maintenance costs.

Accordingly, there is a need in industry for systems and processes ofremoving sulfur from crude oil. Desirably, the system and method allowsweetening of crude oil proximal the removal of the oil from the earth.

Certain embodiments of the invention provide a system and a method forthe removal of hydrogen sulfide from crude oil streams, such as sour oilstreams. In some embodiments, the removal of hydrogen sulfide from sourwater streams is additionally or alternatively provided. The method andsystem for the removal of hydrogen sulfide from a liquid crude oilstream is of lower-cost and of reduced environmental impact thantraditional means. In some embodiments, a system and method to sweetensour oil and water without a need to use hydrocarbons or other catalystsis provided. This is especially useful in the exploratory gas industrywhen access to traditional methods used to sweeten oil and water are notreadily available and could be many miles away. Certain embodimentsinclude a system and a method that comprise collecting the sour oil in acontainer, maintaining the sour oil in an air-free environment, addingwater, and agitating the mixture. Other embodiments of the presentinvention include using sour water to remove hydrogen sulfide from souroil.

SUMMARY OF THE INVENTION

The present invention relates to a system and method of processing ofcrude oil. In one embodiment, a system and method are disclosed whereincrude oil is processed in a first subsystem, such as a separator and/orheater, to separate oil components. The first subsystem provides, amongother things, a stream of crude oil to a second subsystem, whereinhydrogen sulfide is removed from the crude oil. In one embodiment, thecrude oil is bunker oil. Bunker oil is generally any type of fuel oilused aboard ships, commonly distinguished as two main types: distillatefuels and residual fuels.

Elemental sulfur and sulfur compounds are naturally present in manypetroleum crude oils. For example, crude petroleum from Saudi Arabiacontains about 5.0 weight percent sulfur, with sulfur containingcompounds present in the crude often comprising high concentrations ofhydrogen sulfide, which is a gas at room temperature. These sulfurcompounds are unlikable because of their disagreeable odors and becausethey oxidize to sulfur dioxide or hydrogen sulfide which are corrosive.Sulfur containing crude oil can generate hydrogen sulfide and othersulfur containing gases during transportation and handling which poses aserious health hazard to workers in the immediate area around the crude.The corrosive nature of sulfur compounds contributes significantly tothe costs of construction, operation, and maintenance of a petroleumrefinery. As a result, crude oils and bunker oils that emit sulfurspecies have a low market value.

Lower-boiling hydrocarbons contain lower-boiling sulfur compounds andhigher-boiling hydrocarbons contain higher-boiling sulfur compounds.Many prior art systems and methods have been employed to attempt tosweeten and desulfurize petroleum stocks, including oxidation reactions,solvent extraction, adsorption, and metal catalysis. Oxidation reactionsrequire the addition of chemical reagents that oxidize sulfur componentsto form sulfides and/or disulfides, usually in the presence ofundesirable metal reactants. Solvent extraction processes desulfurizesour hydrocarbons by extracting the sulfur components from thehydrocarbons with a suitable solvent that is immiscible with thehydrocarbons and typically require phase separation. Adsorptionprocesses employ contact with a suitable high surface area adsorbent todesulfurize sour hydrocarbons, typically using refractory oxides such assilica and alumina or molecular sieves. Catalytic metals associated withporous supports have also been used to remove sulfur fromsulfur-containing hydrocarbon streams. Still other processes employelevated temperatures and pressures and large quantities of hydrogen gasin the presence of special catalysts to form hydrogen sulfide.

Oil, natural gas, and water with a high concentration of sulfurcompounds such as hydrogen sulfide and sulfur dioxide are referred to as“sour.” Hydrogen sulfide is a colorless, toxic, flammable gas that isresponsible for the foul odor of rotten eggs. Hydrogen sulfide is ahighly toxic and extremely deadly gas. The industry considers oil orwater containing 100 parts per million (“ppm”) (0.01%) sulfur sour oiland sour water. High concentrations of hydrogen sulfide, far away fromhydrogen sulfide removal facilities, presents a problem of transportingthe sour water and sour oil. In addition to ocean-going vessels of crudeoil and the bunker oil employed as fuel therefore, rail shipment ofcrude oil and bunker oil is another option for moving oil out of highproduction areas with little pipeline access. The shipping industry isadversely affected by having to address the shipping of hydrogensulfide. The solution to rail safety issues are typically unanticipatedcosts, including rail car investments or new safety protocols to addressthe transport of sour oil.

Even if the sour water and sour oil is treated to remove hydrogensulfide content through conventional methods of using scavengers orother treating chemicals, facilities will not accept the treated wateror oil if it contains too much of the treatment chemicals. This isespecially problematic with wells containing high levels of hydrogensulfide that require more of the treatment chemicals to remove thehydrogen sulfide concentrations. Added to these problems are the manyregulations in place regarding the treatment and disposal of sour oiland sour water, such as OSHA regulations that require less than 10 ppm(0.001%) of hydrogen sulfide vented into the open air. With wellsapproaching or exceeding 10,000 ppm (1%) hydrogen sulfide, the cost ofusing liquid scavengers on the oil and water products exceeds the valueof the oil itself after transportation costs. Such liquid scavengers arethemselves very noxious chemicals and workers dealing with thesechemicals must wear full HAZMAT suits. Hydrogen sulfide is lethal ifinhaled in concentrations down to 1000 ppm (0.1%) in air or water or oilvapor. While at low concentrations, hydrogen sulfide has acharacteristic smell of rotten eggs, at higher concentrations, therotten egg odor is lost due to hydrogen sulfide fatiguing the sense ofsmell. In addition to the health hazards due to exposure to hydrogensulfide, hydrogen sulfide is a flammable gas that creates additionaltransportation hazards.

In one embodiment, bunker oil is processed so as to remove sulfur (andother pollutants). Generally, the system and method are to make use ofthe addition of water and an emulsifying agent to heated bunker oil,thereby creating an emulsion of oil and water. The emulsion is thensubjected to an electric field, microcavitation, and finally anelectrolysis chamber. After the emulsion is separated, the cleaned“bunker oil” is sent to the storage tank, and the separated water isrecycled (after the addition of caustic soda and/or magnesium oxide).Alternatively, or additionally, the process of FIG. 3 (described below)may be employed to, among other things, assist or enable the removal ofhydrogen sulfide and/or sulfur.

Bunker oil requires cleaning, as it is the lowest grade of diesel fueland generally contains high quantities of sulfur (3.5-4.5% by weight).When the fuel is used in the diesel engines of the cargo ships, highconcentrations of sulfur and sulfur components are released into theatmosphere in the exhaust stream. Current methods to clean exhaustemissions (gas scrubbers and catalytic converters) are ineffective wheninitial sulfur content exceeds 1% by weight (sulfur clogs catalyticelements that remove NOx).

Many ports have issued regulations that limit pollutants, inclusive ofsulfur, at concentrations below 0.5%. As such, cargo ships using highsulfur bunker oil as fuel must discontinue use of the diesel engineswhile in port and run an electric power line from shore to the ship, topower ship functions. This leads to higher cost of operation. If sulfurfrom bunker oil is removed while in the liquid state to, e.g. to levelsbelow 0.5%, the resulting cleaned bunker oil in the diesel enginesallows use of conventional methods of exhaust stream cleaning, such asscrubbers and catalytic converters.

More specifically, the process may be provided as comprising 3 phases,or stages. Each will be discussed in some detail. In a Stage 1: AnEmulsifying agent is introduced into the untreated bunker oil,containing 3.5-4.5%, and is heated to “an appropriate temperature” toincrease the likelihood of forming a stable emulsion with water. Theheated bunker oil, containing the emulsifying agent, is then introducedto a mixing unit, where water is sprayed into the bunker oil, and mixedwith the bunker oil, until an emulsion is created. The creation of theoil/water emulsion is accomplished by flow through nozzles which induceturbulent flow of the oil/water mixture and is stabilized by theemulsifying agent which was initially added to the oil prior to heating.During the mixing stage, a large amount of sulfur which was contained inthe bunker oil is separated from the oil component of the fuel andtransfers to either the water or a gaseous form of sulfur, such ashydrogen sulfide.

In one embodiment, the optionality exists to subject the oil/wateremulsion to an electric field prior to entry into an oil/waterseparator, which is done to increase the amount of sulfur which leavesthe bunker oil and combines either with the water or with hydrogen gasto form hydrogen sulfide in a gas form, which can be vented.

After separation at the end of Stage 1, the water used in Stage 1 isdiscarded as wastewater, and the fuel is then sent to Stage 2.

At Stage 2: The bunker oil is once again mixed with water to create astable emulsion. Preferably, the emulsion in the second mixing stage isonce again subjected to an electric field to increase the Sulphurquantity which leaves the bunker oil and is combined with the water, orforms vented hydrogen sulfide gas.

At Stage 3: After exiting the second mixer stage, the emulsion of waterand bunker oil is sent to a microcavitation chamber in which highintensity acoustic waves are introduced to the emulsion to createcavitation bubbles in the emulsion. The cavitation process increases theamount of sulfur released from the bunker oil. After exiting themicrocavitation chamber, the emulsion is once again subjected to anelectric field in a “reaction chamber. Stated in more detail here, theelectric current provides sufficient energy to strip additional sulfurmolecules from the bunker oil, as well as to split some of the watermolecules into gaseous hydrogen and oxygen. The hydrogen gas moleculeshave a high affinity for sulfur and will create hydrogen sulfide whichcan be vented. In addition, some of the hydrogen sulfide may dissolveinto the water and create highly diluted hydrosulfuric acid.

The emulsion then exits the reaction chamber and is moved to a water/oilseparator, where water is removed from the emulsion. The “cleaned”bunker oil is then sent to a fuel storage tank, and the water isrecycled for use as makeup water in the first mixing stage (Stage 1).Sodium hydroxide may also be added to this recycled water stage, priorto being sent to the first mixing stage. Alternatively, magnesium oxidemay also be added.

According to principles of the various embodiments as discussed herein,an apparatus and method are described which remove a large amount of thepollutants and, in particular, sulfur from the bunker oil while it is inthe liquid state, prior to being further processed, or burned in acombustion engine. The system is able to operate to clean the fuelonboard the ship as it runs through fuel lines in preparation for beingin the diesel engine. The system removes these pollutants, and inparticular sulfur, from the bunker oil before it is placed in the fuelservice tank so that as the oil is burned, the amount of sulfur in theexhaust gas is less than 0.5%. This is sufficiently low that an SCRcatalytic converter and other scrubber can now be used to remove otherpollutants from the exhaust smoke, such as NOx. Since the sulfur hasbeen removed from the exhaust gas, an exhaust scrubber can now be usedto remove many other pollutants from the exhaust gas since it will nolonger be clogged with sulfur. The inventive system permits thisachievement by removing sulfur from the bunker oil before it is burnedto be within the limits needed for the exhaust gas scrubber to removeother pollutants.

The combination of the removal of sulfur from the liquid bunker oilfollowed by the removal of any additional sulfur along with a variety ofother pollutants from the exhaust gas using the appropriate scrubbersand catalytic converter results in a substantially clean output from theexhaust stack on the huge cargo ship, permitting the cargo ship to dockin port and run its diesel engines while meeting all environmentalregulations.

The system as described herein also enables the cargo ship to increaseits exhaust gas efficiency and remove even more heat from the exhaustgasses than was previously possible. In the past, it was necessary tokeep the exhaust gas at extremely high temperatures to avoid the sulfurcondensing on the sidewalls of the smoke stack which would corrode anddestroy the metal lining in a short period of time. With the inventivesystem as discussed herein, the exhaust gas is sufficiently free ofsulfur that the temperature of the exhaust gas can be significantlylower. This permits the capture of substantially more energy from theburning of the diesel fuel and greatly increases the efficiency of thediesel engine itself as well as the exhaust gas boiler. As is known, thelower the temperature of the exhaust gas from a combustion system, thehigher the overall efficiency since more energy has been extracted fromthe combustion cycle. Accordingly, by permitting a lower exhaust gastemperature, the fuel-efficient operation of the cargo ship as a wholecan be greatly increased.

According to one embodiment, the system includes a fuel flow linethrough which bunker oil can flow from a storage tank. After the fuelleaves the storage tank, an emulsifying agent is mixed with the fuel inone embodiment in order to increase the affinity of the oil mixing withwater. The fuel line then enters a heat exchanger followed by a heaterin which it is heated to an appropriate temperature to increase thelikelihood of mixing with water. Next, the fuel enters a mixing unit, inwhich water is sprayed into and mixed with the bunker oil, creating anemulsified blend of diesel fuel and water. The mixing is subject tohighly turbulent flow and sprayed through nozzles to encourage completemixing with the water and oil.

In one embodiment, during the mixing stage, an electric coil that iswrapped around the mixer stage subjects the emulsified fluid to anelectric field. The emulsified mixture exits the mixing stage and entersa water/oil separator stage which separates the water from the oil.During the mixing stage, a large amount of the sulfur which wascontained in the bunker oil is separated from the oil component of thefuel and transfers to either the water or a gaseous form of sulfur, suchas hydrogen sulfide. In a first separator stage, the water which hasbeen separated from the fuel is discarded as waste water and the fuel isoutput to a pipe to enter a second mixer stage. In the second mixerstage, the fuel is once again mixed in a turbulent flow with water tocreate an emulsion that contains water and oil. Preferably, during themixing in the second stage, the emulsion is subjected to an electricfield in order to increase the quantity of sulfur which leaves thebunker oil and combines either with the water or with hydrogen gas toform hydrogen sulfide in a gas form, which can be vented.

After the emulsion exits from the second mixer stage, it passes througha microcavitation chamber in which the emulsion is subjected to highintensity acoustic waves that create cavitation bubbles in the emulsion,further increasing the separation of sulfur from the bunker oil. Theemulsion then exits the microcavitation and enters a reactor chamber inwhich an electric current is passed through the emulsion. The electriccurrent passing through the emulsion adds additional energy to furtherseparate individual components of the emulsion. In particular, theelectric current which passes through the emulsion will providesufficient energy to strip some of the remaining sulfur atoms from thebunker oil. In addition, the electric current will provide sufficientenergy to split some of the water molecules into the gaseous componentsof hydrogen and oxygen, creating bubbles of hydrogen and oxygen. The gasbubbles of hydrogen will have a great affinity for the sulfur and willcreate gas molecules of hydrogen sulfide which can then be safely ventedfrom the reactor chamber. In addition, some of the hydrogen sulfide maydissolve into the water and create a highly diluted hydrosulfuric acid.The electrolysis of the emulsion also creates oxygen gas from thesplitting of the water molecule and the individual oxygen atoms quicklycombine either with another oxygen atom to create oxygen or with otherpollutants in the oil, for example lead resulting in lead oxide;arsenic, resulting in arsenic trioxide sulfur to create sulfur dioxide;or other compounds of oxygen. The emulsion exits from the reactor andenters a water-fuel separator where the water is removed from the oil.The twice cleaned fuel is output for storage in a fuel storage tank andthe water is input as the water mixture to the first mixture to be usedfor mixing with the oil in the first mixer to create the first emulsion.

In one embodiment, prior to the cleaning water being inserted into themixer of the second stage, one or more treatment chemicals may be addedto the water in order to increase the solubility to sulfur. For example,one of the chemicals which may be added in is sodium hydroxide, as knownas caustic soda. This creates a strong alkaline solution of the waterwhich, when mixed with the oil, assists in the separation of sulfur fromthe bunker oil. Sodium hydroxide in water will act to dissolve grease,oil fats and protein deposits. Another chemical which may be used ismagnesium oxide which can react with the sulfur in the bunker oil tocreate magnesium sulfide which is a salt that can be easily removed fromthe bunker oil. This also provides additional hydrogen atoms to combinewith the sulfur to create H₂S and remove the sulfur from the bunker oilcompound.

Fuel which passes through the two-stage mixer and water-fuel separatorsystem has been found to have substantial portions of the sulfurremoved, resulting in bunker oil which is sufficiently free of sulfur(in the range of 0.5% or lower), and other contaminants that it can beburned while in port and meet pollution control standards. It alsopermits use of smokestack scrubbers and catalytic converts in the outputexhaust to further remove other contaminants which has not beenpreviously possible for large cargo ships burning standard bunker oil.

Various embodiments of the present invention are directed to the removalof undesired sulfur compounds, including hydrogen sulfide gas, fromoils, and in particular crude oil. The transport of oil in ocean-goingvessels, such as tankers, typically involves simply filling of suchmassive ships with oil and the transit thereof to a distant shore, wherethe oil is then off-loaded and then refined to various stages at arefinery. One aspect of the present invention is directed to the abilityto conduct certain processing of the oil while it is in transit toimprove the quality of the oil upon arrival at the tanker's destination.Thus, in several embodiments of the present invention a system andmethod are described that includes the reduction of sulfur compounds,and especially hydrogen sulfide, from oil being transported—while it isbeing transported. Achievement of this objective preferably involves thesimple employment of water (whether fresh or sea water) and air, and byprocessing the oil contained on a tanker by the described contact withthe water, followed by the water being contacted by additional air, thesulfur load of the oil being transported is effectively reduced, allwithout the employment of expensive chemicals.

Yet other aspects of the present invention are directed to similarsulfur content reductions in oil, including hydrogen sulfide, where theoil is selected from the group consisting of crude oil and bunker oil, avery low quality, dirty fuel of a low grade that is typically used asfuel to power the engines of large ships, including tankers thattransport crude oil, as well as large cargo ships, container ships, andluxury cruise liners. Bunker oil contains a high amount of sulfur in therange of 3%-5%. Traditionally, removal of sulfur from bunker oil has notbeen attempted due mainly to the time and costs involved. In the past,with the absence of air quality regulations, ships were able to use andburn high sulfur oil in a large cargo and tanker ships with littleconcern. But those days are in the past. Increasingly, the burning ofsuch dirty, low quality bunker oil is being prohibited in ports wheresuch large ships depart and arrive. Various ports around the world areissuing regulations that limit the amount of sulfur emissions from aship while it is within the port boundaries, with a typical restrictionbeing that the bunker oil contain less than 0.5% sulfur before it can beused to power a diesel engine within the port boundaries. Since bunkeroil having such a low sulfur content is not available on the market,many ship operators must completely shut down their diesel engines whenthey are docked at a port and use land electric lines for poweringsystems on the ship which can be extremely expensive for the city toprovide the high power capacity of a ship and also expensive for theship operator to purchase the electricity. Removal of sulfur fromexhaust gas of engine ships is impracticable as traditional exhaust gasscrubbers only work when sulfur level is below 1%. There is therefore along felt but unsolved need for a way to reduce the amount of sulfur inbunker oil, as well as in the oil being transported by oil tankers,including the removal of hydrogen sulfide from such oils, in a safe andeconomical manner. As described herein, the present invention addressesthese problems in an economical, simple manner.

The present invention can be used with sour water and sour oil with highlevels of hydrogen sulfide as well as lower levels. The hydrogen sulfideis removed without specialized equipment or expensive chemicals. Thesweetened water or sweetened oil can be transported without placingthose involved in handling and transportation at risk of potentiallyfatal mishaps and minimizes and environmental hazards.

As used herein, the term “sour oil” refers to oil containing levels ofhydrogen sulfide in an amount greater than 100 ppm (0.01%). Sour oil canalso mean oil containing 0.5% or more sulfur by weight. The term “sourwater” refers to water containing hydrogen sulfide in an amount greaterthan 100 ppm (0.01%). The terms “sweet,” “sweetened,” and/or“sweetening” mean a product that has low levels of hydrogen sulfide, hashad hydrogen sulfide removed, or the process of removing hydrogensulfide. The term “stripping” means removing hydrogen sulfide from waterand/or oil. The terms “acceptable limits” or “acceptable amounts” or“acceptable levels” refer to the maximum amount of hydrogen sulfideallowed according to any of the pertinent regulations.

In certain embodiments, the invention comprises an air source, a tank, aplurality of lines that distribute air from the air source to the tankand a vent stack, connections that distribute the air from the airsource into the tank, a hydrogen sulfide monitor, and a vent stackconnected to the water tank and air source. The air from the air sourceruns to a tank filled with sour water through an airflow line. Theairflow line is connected to a pipe with at least one hole. The pipe islocated in the water tank. A second line runs to the vent stack througha second airflow line. In certain embodiments, air flows to the ventstack at a rate of 120 standard cubic feet per minute (“scf/m”). Theairflow may be adjusted incrementally every hour for twelve hours. Theair distribution ratio may be adjusted hourly. The amount of hydrogensulfide is measured near the top of the vent stack. The air with theacceptable levels of hydrogen sulfide is then vented. The plurality oflines running from the air source are secured by typical ways known tothose skilled in the art to connect air lines to air source. Embodimentsof the present invention ensure that any materials containing hydrogensulfide are enclosed within the invention and not exposed to the outsideenvironment. As those skilled in the art will recognize, the air sourcecan be any air source able to generate air, such as a compressor or ablower.

U.S. Pat. No. 3,547,190 issued to Wilkerson (“Wilkerson”), describes anapparatus and method for treating wastewater associated with hydrocarbonproduction. Wilkerson is incorporated by reference in its entirety.According Wilkerson, waste water from a well is pumped under pressure toa plurality of spray nozzles which are disposed in such a manner as tospray the water into the atmosphere in a substantially verticaldirection in open air. The sprayed water is thus aerated to remove theresidual hydrogen sulfide therefrom and reduce its temperature. Thewater is then collected in a basin wherein any excess oil stillassociated with the water may be skimmed from the surface of the water.The method described in Wilkerson would lose efficiency as thetemperature of the process water decreases from boiling point. In somespecific field applications where water coming from the well itself isvery hot, this method may be useful. For all other field applications,there are problems with its implementation. For example, it operates ina fairly narrow envelope of parameters, both mechanical and process.Nozzle-size and upstream pump pressures will be fairly critical. It mayresult in mist (as opposed to vapor) being blown onto adjoiningproperty, legally a spill. Wilkerson requires hot water for efficiencyand may not be suitable for cold-weather applications, regardless of thetemperature of the initial process water.

Of note, Wilkerson vents hydrogen sulfide without regard to safelybreathable concentrations. Any hydrogen sulfide not vented in theinitial pass vents from an open body of water at a rate that is bothdifficult to measure and difficult to control. This particular method isvery problematic in this regard, and as those skilled in the art canrecognize, the present invention alleviates the safety hazardsassociated with releasing hydrogen sulfide into the environment.Although it is known in the art that exposing water or oil containinghydrogen sulfide to air will remove hydrogen sulfide, embodiments of thepresent invention allow the aeration to remove hydrogen sulfide in anenclosed environment to eliminate any safety risks and environmentalhazards associated releasing hydrogen sulfide in an open environment.

In other embodiments, the present invention comprises a container filledwith water, a separate container filled with oil, a means to distributewater from the container filled with water to the container filled withoil. The water can be sweet water or sour water having a sourconcentration less than that of the sour oil. The water travels throughthe sour oil as it has a lower specific gravity. This travel through theoil creates an agitation, and the hydrogen sulfide is removed from theoil as the water passes through the oil. The agitation occurs at theoil/water interface. Oil will release hydrogen sulfide into the waterwherever water containing a lower hydrogen sulfide concentrationcontacts oil containing a higher hydrogen sulfide concentration.

U.S. Pat. No. 3,977,972 issued to Bloch et al. (“Bloch”) describes asystem and a method to remove hydrogen sulfide from seal oil throughbubbling a gas such as nitrogen. Bloch is incorporated by reference inits entirety. Bloch's preferred embodiment contains a compressor havinga shaft which rotates in a pair of liquid-film seal cartridges whichserve as seal retainer housings for the rotary shaft of the compressor.Each of the liquid-fill seal cartridges includes a pair of floating,non-rotation sleeve portions surrounding the shaft and interconnected byan intermediate space portion through which the shaft freely extends.Contaminated oil is then transferred to a cylindrical drum, where thediameter of the drum may be on the order of two feet while its heightmay be approximately twice the diameter. The lower interior portion ofthe drum is provided with a baffle in the form of a simple flat sheet ofmetal extending upwardly approximately 2 feet from the bottom of thedrum to divide the lower interior portion of the drum into a pair ofchambers which has a cross section of a semicircle. Contaminated sealoil flows into one of the chambers, where a sparger means bubbles up airor nitrogen through the oil. The oil flows to the second chamber, wherea sparger means bubbles up air or nitrogen through the oil. Bloch, whilepossibly suitable for refined seal and lubrication oils that may becomecontaminated by higher sulfur fuels, is neither suitable nor safe to usewith crude oils or any other oil that releases combustible case into theair. Although the use of pure nitrogen or another inert gas mightaddress combustion problem, it is impractical and uneconomical to obtaina pure nitrogen source at exploratory sites, and would also create a lowoxygen environment (breathable oxygen) in the area near the vent.Neither is it suitable for higher concentrations (above 10 ppm) ofhydrogen sulfide due to its direct, un-diluted vent. As those skilled inthe art can appreciate, the use of water to remove hydrogen sulfidecontent in oil reduces the risks associated with adding an outside airsource to a combustible material such as oil.

In certain embodiments, nitrogen can be used to keep the oil-waterinterface fresh, where the water agitation sweetens the oil. Nitrogen isintroduced into the bottom of the oil stripping tank periodically at alow volume, for example, at a rate of 10 standard cubic feet every 15minutes as an additional safety measure to prevent flammable gasbuildup.

In certain embodiments, the present invention comprises a tank with amixture of sour oil and water, a separate tank with sour water, airdistributors pumping air through the tank with sour water to removehydrogen sulfide, pumping the sweetened water into the tank containingthe oil and water mixture, and allowing the water from the oil and watertank to flow into the sour water tank through a gravity-feed. As thoseskilled in the art can appreciate, the present invention is animprovement to the prior art that requires the use of catalysts,scavengers or other expensive and specialized equipment.

Certain embodiments of the present invention can be implemented usingcontainers typically used in the oilfield, such as commonly used 500barrel “frac” tanks and 400-barrel cylindrical upright tanks. In oneembodiment, a 185 scf/m air compressor derated for 5000 feet elevationto 140 scf/m can be used as the air source. A disperser bar with atleast one hole is placed in the water tank. The disperser bar can be 1″or 1.5″ pipe. The vent line from the water tank to the vent stack is 3″in diameter.

The equipment described herein is provided as an example only and shouldnot be construed to limit the present invention, as the presentinvention can be used in almost any scale, For example, the presentinvention can be used with samples smaller than 500 ml oil or water aswell as tanks having a volume in excess of 1000 barrels.

For example, certain embodiments comprise equipment that can be placedin mobile transportation, such as a trailer or the back of a pickuptruck. Certain tanks, which are commercially available, are designed tofit in the back of a pickup truck. This embodiment allows easy transportand allows sour oil and sour water located in remote locations wherelarger equipment is uneconomical, impractical, or impossible because ofthe remote area.

In certain embodiments, the equipment can be placed in a tow trailer,where the invention comprises a configuration comprising an automationcabinet, an air source, a power source, such as a generator, a waterpump, and hose or piping connectors. As those skilled in the art canappreciate, variations of this embodiment can also be practiced withother types of tanks that are mobile and can be transported from site tosite, and are within the spirit of the invention. The descriptionsherein are not intended to limit the present invention.

In certain embodiments, the invention comprises an air source, aplurality of storage devices, connections that distribute the air fromthe air source into a storage device comprising water, and a vent stackconnected to the storage device comprising water and air source. The airfrom the air source runs to the storage device comprising sour waterthrough an airflow line. The airflow line is connected to a pipe with atleast one hole. The pipe is located in the storage device comprisingsour water. A second line runs to the vent stack through a secondairflow line. In certain embodiments, air flows to the vent stack at arate of around 120 scf/m. The airflow may be adjusted incrementallyevery hour for twelve hours. The air distribution ratio may be adjustedhourly. The amount of hydrogen sulfide is measured near the top of thevent stack. The air with the acceptable concentrations of hydrogensulfide is then vented. The sweetened water is then pumped from thewater tank to a second storage device comprising a mixture of sour oiland water through an attachment connecting the water tank to the top ofthe second storage device comprising sour oil and water. The storagedevice comprising a mixture of sour oil and sour water is equalized. Forexample, in embodiments comprising 400- or 500-barrel tanks, a suitablerate would be pumping water from the storage device comprising waterinto the storage device comprising the mixture of sour oil and water ata rate of 3 barrels per minute. Other rates are also possible, such asrates as low as 20 to 50 gallons per minute or as high as 10 to 20barrels per minute. As the water passes through the oil due to itshigher specific gravity, hydrogen sulfide is removed from the oil. Thewater that is now at the bottom of the storage device comprising oil andwater has higher concentrations of hydrogen sulfide. The water from thebottom of the storage device comprising oil and water flows back to thestorage device comprising water due to hydrostatic pressure, i.e., a“gravity feed,” through an attachment between the bottom of the storagedevice comprising oil and water tank and storage device comprisingwater. The water is then stripped to remove hydrogen sulfide so that theconcentrations of hydrogen sulfide reach a level that is acceptable tovent. Embodiments of the present invention ensure that any materialscontaining hydrogen sulfide are enclosed within the invention and notexposed to the outside environment.

Certain embodiments of the invention include a cavitation vent to keepair out of the oil stripping tank.

In certain embodiments of the invention, the water used in the strippingprocess comprises a pH of approximately 7.2 or below. In certainembodiments, the removal of all hydrogen sulfide may be desired. Inembodiments where all hydrogen sulfide is desired to be removed, thehydrogen sulfide could be completely removed when fluid temperatures areabove 45 degrees Fahrenheit.

Another embodiment of the invention includes a way to automateregulation of air distribution. In certain embodiments, a loopcontroller is attached to a hydrogen sulfide sensor monitoring theconcentration of hydrogen sulfide from the vent stack. In thisembodiment, the loop controller is attached to the vent stack, the airline to the water stripping tank, and the air line to the vent stack.The loop controller is used to keep the air vented below 10 ppm. Theloop controller is connected to a current to pressure converter (“I to Pconverter”). In certain embodiments, the I to P converter converts thecontroller 4 to 20 ma output to 0 to 15 psi pneumatic. As those skilledin the art can appreciate, different types of I to P converters may beused with the present invention, and the I to P converter describedherein is not intended to limit the present invention.

Certain embodiments include at least one I to P converter. A specificair line could be regulated by a dedicated I to P converter. In otherembodiments, the I to P converter could regulate a plurality of airlines. In preferred embodiments, the use of one I to P converter may beadvantageous because it assures a “safe state” upon loss of controlsignal (either electric or pneumatic) where all the air would divertinto the vent stack, and the valves would return to their defaultposition.

Based on the information received from the loop controller, the I to Pconverter or converters will send more air to the air line connected tothe vent stack and less air to the air line connected to the tankcomprising water, i.e., the water stripping tank, as the hydrogensulfide stream exceeds 10 ppm when the hydrogen sulfide monitor reads aconcentration exceeding 10 ppm. If a concentration detected by thehydrogen sulfide sensor falls below 10 ppm, the loop controller sendsmore air to the air line connected to the water stripping tank. Incertain embodiments, the loop controller could be calibrated where itwould reset at a one-minute interval and calibrated so that there is avariance range of 2 to 3 ppm where no change in control to the air lineswould be transmitted.

In certain embodiments, the automation can be controlled with anautomation control. The automation control allows for measurement of thenumber of barrels of oil sweetened by the present invention.

In certain embodiments, the automation control comprises a programmablelogic controller (“PLC”), a plurality of compartments, an air source,connections that distribute the air from the air source to the desiredcompartments, a pumping means, sensors, sensor cables, and a vent stackconnected to a compartment comprising water. A first compartment isfilled with water which can comprise hydrogen sulfide. A secondcompartment is filled with a mixture comprising sour oil and sweet waterin an equalized amount. The sensors are attached by sensor cables to thecompartments comprising water, sour oil and water, and a vent stack.Water from the first compartment is distributed to the secondcompartment through a connection located at the top of the secondcompartment. As the water passes through the oil due to its higherspecific gravity, hydrogen sulfide is removed from the oil. The sensorin the second compartment detects the amount of hydrogen sulfide in thesecond compartment. The water that is now at the bottom of the secondcompartment has higher concentrations of hydrogen sulfide. The waterfrom the bottom of the second compartment flows back to the firstcompartment comprising water due to hydrostatic pressure through anattachment between the bottom of the second compartment and the firstcompartment. The sensor in the first compartment measures the amount ofhydrogen sulfide in the first compartment. The sensor in the vent stackalso measures the amount of hydrogen sulfide in the vent stack. Air isdistributed to the first compartment from the air source through anairflow line. The sensor in the first compartment measures the amount ofhydrogen sulfide present in the first compartment. The sensor in thevent stack measures the amount of hydrogen sulfide present in the ventstack. Once the sensor detects the amount of hydrogen sulfide is withinthe desired limit programmed into the PLC, air is automatically vented.Sweetened water is then pumped from the first compartment to the secondcompartment. As those skilled in the art can appreciate, the sensorsmonitor the amount of oil sweetened by the process.

In other embodiments, the data regarding the number of barrels of oilsweetened is transferred remotely to a database where the number ofbarrels of oil sweetened can be stored and analyzed. This data transfercan occur via wireless means including cellular internet protocol,Bluetooth, or other wireless data transfers.

Other embodiments use a high pressure, low volume water pump tocirculate stripped water through a sample to remove hydrogen sulfide.These embodiments comprise an air compressor or air pump, a containerused as a water stripping reservoir, a high pressure, low volume pump, arelief regulator, a container filled with an oil sample pressurized tothe sampled psi, a container filled with a water sample, and a liquidpressure regulator. The air compressor or air pump pumps air into thereservoir containing water to be stripped. For example, a CoralifeSL-381.3 scfm pump may be used. Air is then pumped into a waterstripping reservoir. The water stripping reservoir is at atmosphericpressure. An example of the water stripping reservoir may comprise aplastic or metal material with a five- to ten-liter capacity. The waterstripping reservoir is filled to ¾ or ⅝ of its volume capacity withdistilled water. Water from the water stripping reservoir then travelsto a high pressure low volume pump. The pump may comprise a pneumaticpump or an electric pump. For example, the pump may comprise a Texsteam5000 series. A relief regulator is connected to the high pressure lowvolume pump, and vents as necessary. As an example, the relief regulatormay be set at the sample container MAOP, such as 2000 psi. The waterfrom the high pressure low volume pump then travels to a container withthe oil sample. For example, certain embodiments may use a 1000 cubiccentimeter (“cc”) container, pressurized at 75 psi. The water passesthrough the oil sample container to a separate container, containing awater sample. In certain embodiments, the container for the water samplemay comprise a 1000 cc container. The water then passes from the watercontainer back to the water stripping reservoir. A liquid pressureregulator may be attached to the line traveling from the container withthe water sample to the water stripping reservoir. The liquid pressureregulator may be set at the oil sample pressure, e.g. 75 psi.

In yet another embodiment, the present invention comprises a containerfilled with water, a separate container filled with oil, a distributingmeans that distributes water from the container filled with water to thecontainer filled with oil.

In certain embodiments, the invention includes of filling a tank withsour water, aerating the sour water to strip the sour water of entrainedhydrogen sulfide gas, pumping the sweetened water into a separate tankcomprising an equalized mixture of sour oil and water, removing hydrogensulfide from the sour oil, pumping the resulting sour water into thetank filled with sour water.

In certain embodiments, the invention includes components that can beused in remote areas, such as exploratory wells. As those skilled in theart can recognize, the invention eliminates the need for expensive andspecialized equipment that is currently used to remove hydrogen sulfidefrom sour water and sour gas. Furthermore, the invention can be used tostrip sour water and treat sour oil containing hydrogen sulfide in anyamount, even exceeding 300,000 up to saturation—an amount higher thanequipment that taught in the prior art. For example, U.S. Pat. No.5,286,389 issued to Hardison (the “Hardison '389 patent”), incorporatedin its entirety by reference, describes a system and apparatus to striphydrogen sulfide from water. The Hardison '389 patent specificallyteaches that the apparatus and method are particularly effective totreat sour water containing around 5 ppm to 500 ppm hydrogen sulfide.Thus, the Hardison '389 patent teaches away from using such prior artwith water containing high levels of hydrogen sulfide. The levels ofhydrogen sulfide do not influence the present invention, and the presentinvention can be used with materials containing very high levels ofhydrogen sulfide.

U.S. Pat. No. 6,444,117, issued to Kahn et al. (“Kahn”), describes aprocess for desulfurizing sulfur-containing crude oil streams. Kahn isincorporated by reference in its entirety. Kahn requires heating thesulfur containing crude oil to an elevated temperature to at least 300degrees Fahrenheit (149 degrees Celsius) to about 600 degrees F. (316degrees C.) for an extended period of time, stirring and bubbling aninert gas, such as nitrogen into the crude oil, and adding a scavengeror catalyst into the crude oil stream to generate an exhaust gas such ashydrogen sulfide. Kahn requires a careful monitoring of and controlliquid temperature to remain safe. Its maximum efficiency envelopeimmediately borders the flash-point of the oil sweetened (unsafe). Theseparameters must be monitored and controlled constantly and will varywidely with different types and grades of crude oil. Kahn acknowledgesthat additional steps may be required to reduce the amount of hydrogensulfide generated by heating the crude to the levels described. Kahnvents both hydrogen sulfide and low-oxygen mixture without regard tosafely breathable considerations. As those skilled in the art canappreciate, the present invention is a much simpler process that is muchsafer than what is known in the prior art.

United States Patent Application No. 2013/0324397, by Wilson et al.(“Wilson”) describes using a carbon adsorbent for hydrogen sulfideremoval. The hydrogen sulfide adsorbent is added to the materialcontaining hydrogen sulfide. Wilson is incorporated by reference in itsentirety.

The present invention involves a system and a method that removeshydrogen sulfide from water and oil in a very cost-effective manner.Furthermore, certain embodiments allow the hydrogen sulfide to beremoved on-site at remote locations, such as exploratory wells. Certainembodiments allow removal of hydrogen sulfide from water and oil,diluting the concentration to amounts that can be safely vented into theenvironment, in accordance with current environmental and safetyregulations and without endangering anyone in the surrounding area, anyanimal in the surrounding area or the environment.

The present invention also reduces sulfur by weight. Typical worldwidedefinition for sour oil is generally about 0.5% sulfur by weight. Thepresent invention can be used to sweeten oil such that the oil is lowerthan the 0.5% acceptable rate.

Other embodiments are directed to improving the price spread, which isthe value of sweet oil versus sour oil, measured in dollars. The pricespread can vary between $5 USD and $16 USD per barrel. It is difficult,and not usually feasible, to blend out high volumes of hydrogen sulfidein oil. It is not difficult, but may be costly, to blend out high sulfurweights. One would have to blend a prohibitive amount of 0% ppm hydrogensulfide with 10,000 ppm oil in order for the resulting total volume tocurrently accepted limits of 0.5% or 5 ppm. By first treating oils asdescribed herein, then blending oils in a 1:1 ratio or equal volumes of0.1% sulfur by weight would result in a sweet-price oil. Blending istypically expensive, but by first treating oils as described herein,provides a low-cost method of minimizing the post-process blendingratio, or eliminates the need to blend oils to increase the pricespread.

Certain embodiments of the present invention include a plurality oftanks containing different levels of sour oil. The oil in one of thetanks can be treated to remove hydrogen sulfide and then blended withoil from another tank to improve the price spread.

Other embodiments comprise an additional chamber where the removal ofhydrogen sulfide from the air can be further stripped thus increasingthe rate of hydrogen sulfide removal before venting once the hydrogensulfide levels are within the desired limits.

In yet another embodiment, the system and method comprise safe transportof sour water and sour oil from a remote area such as an exploratorywell. High concentrations of hydrogen sulfide are extremely toxic anddeadly. Transportation of such materials is extremely dangerous and putseveryone involved at risk, from the personnel handling the materials atthe site, those involved in loading the transportation vehicle, thedriver of the transportation vehicle, to the personnel at the treatmentplant unloading the toxic materials. The danger of a deadly mishapincreases as more people have to handle the toxic materials, and thegreater the distance traveled further puts the handlers at risk. Incertain embodiments, the present invention involves a system and methodto neutralize the risk involved in transporting toxic materials, such assour water and sour oil with high concentrations of hydrogen sulfide. Asthose skilled in the art can appreciate, the present invention rendersthe transport of materials high in hydrogen sulfide unnecessary, thusimproving the safety to those involved in transporting the materials,and reducing liability that may result should an accident occur duringtransportation.

Use of the current invention at exploratory wells is especiallybeneficial. For example, when a crew is at an exploratory well, theytest to see the quality of wells for hydrogen sulfide. At some wells,the levels are extremely high, and cause a danger to any person in thearea. In order for samples to be provided for further analysis, the crewsubjects themselves to the danger not only in the levels of hydrogensulfide in the sour oil and sour water, but also dangers in transportingsamples. In order to transport any of the sour oil or the sour water, acrew would have to wear full protective gear to load the truck tankers.Then the crew would have to travel over arduous roads with sour oil orsour water containing hydrogen sulfide in such high concentrations thatit could cause sudden death. Any accident along the way would releasesuch hazardous chemicals, and could kill the drivers, as well as dueextensive harm to the environment. Even when the drivers reach thesample or treatment facility, the crews at those facilities are placedat risk. Any error in the process could prove fatal.

The present invention neutralizes this risk. In certain embodiments,there is no need for expensive chemicals, which themselves arehazardous, and the invention eliminates the need to haul a potentiallydeadly toxin or toxins long distances, whether hydrogen sulfide,chemical scavengers, chemical catalysts, or other chemicals. Otherembodiments allow oil and water with high concentrations of hydrogensulfide to be sweetened on site before loading the trucks to transport,transporting the sweetened water or oil, and unloading the sweetenedwater or oil at a facility that will run further analysis or even tosell the sweetened oil.

For example, in certain embodiments, sour oil or sour water would bedetected at an exploratory site, far away from a facility that couldtreat the sour oil or sour water to remove levels of hydrogen sulfide.In this embodiment, the sour water and sour oil is treated in accordancewith the present invention at the exploratory site for easytransportation. This includes aerating sour water contained in one tank,monitoring the amount of hydrogen sulfide concentration in the watertank, venting air from the vapor space of the water tank when thehydrogen sulfide is at acceptable levels, pumping the sweetened waterfrom the water tank into a separate tank containing an equalized souroil and water mixture, continuing to pump water into the tank containingthe oil and water mixture until the amount of hydrogen sulfide in theoil is at acceptable levels, returning water from the tank containingoil and water to the water stripping tank, continuing to aerate thewater until the levels of hydrogen sulfide are acceptable. Then, the oilis removed from the tank containing oil and water, loaded into anothercontainer for shipment, such as a tanker. The oil, having little to nohydrogen sulfide content is then transported from the exploratory siteto a destination where the oil could be subjected to other tests, oreven sold. The water could be re-used in the process, or could betransported from the exploratory site to a destination for furthertesting or disposal. As those skilled in the art can appreciate, therisks involved in transportation of materials containing hydrogensulfide is reduced or eliminated, as the transported materials containlittle or no hydrogen sulfide. In other embodiments, the inventionaddresses an unknown danger except for those involved regardingtransportation of sour oil or sour water. In certain embodiments, thetransportation method comprises shipping oil or water via a commoncarriers or private carriers, including via FedEx or UPS. Since there islittle to no hydrogen sulfide in the materials, no additionalprecautions need to be taken to ship the materials.

Other embodiments of the present invention include a container thatindicates the levels of hydrogen sulfide in the materials within thecontainer. In these embodiments, the container provides a certainindication that the levels of hydrogen sulfide are below toxic amountsand can be transported safely. The container and display can becalibrated according to the relevant regulations to indicate when thehydrogen sulfide level content is below the required levels. This isparticularly useful when further analysis on samples from a remote wellneed further analysis at an off-site location. One of the importantaspects of the present invention is its flexibility to be used inmultiple scales. Thus, hydrogen sulfide can be removed from smallervolumes of sour water or sour oil by the present invention, such aswithin a specialized container that indicates that the materials withinthe container are safe to ship. In another example, the calibration canbe set to indicate that no hydrogen sulfide is present, and the oilcould be sold to a refinery.

Yet another embodiment of the present invention comprises an indicatorthat displays a corresponding message or display regarding the amount ofhydrogen sulfide content in the materials to be shipped. The indicatorcan be integrated with a container, or as a stand-alone indicator. Theindicator displays information on proper handling of the materials thatare to be transported. With the information, decisions on safe handlingand safe shipping of the materials can be made. For example, a decisionto ship the materials via truck, via parcel, via common carrier, orwhether the materials are even safe to transport at all can be made fromthe information. For instance, if the indicator displays that thehydrogen sulfide level is close to zero, this indicates safe shipping byany shipment method that would allow the transport of non-hazardousmaterials like those being shipped.

While various embodiments the present invention have been described indetail, it is apparent that modifications and alterations of thoseembodiments will occur to those skilled in the art. However, it is to beexpressly understood that such modifications and alterations are withinthe scope and spirit of the present invention, as set forth in thefollowing claims. Further, the invention(s) described herein are capableof other embodiments and of being practiced or of being carried out invarious ways. In addition, it is to be understood that the phraseologyand terminology used herein is for the purposes of description andshould not be regarded as limiting. The use of “including,”“comprising,” or “adding” and variations thereof herein are meant toencompass the items listed thereafter and equivalents thereof, as wellas additional items.

In one embodiment, the present invention further involves the combiningof heavy oil with water to form a heavy oil/water mixture, subjectingthe oil water mixture to ultrasonic waves to create bubbles, and incertain cases, heating the mixture between 150 degrees C. and 350degrees Celsius. This is distinguished from prior art system, forexample those that require a high-pressure system that involve complexequipment and a highly controlled environment. Other prior art systemsemploy expensive systems that use electrodialysis or membranes and whichrequire complex mechanical and process parameters not suitable for fielduse and that are not at all not portable.

In one embodiment, the present invention is devoid of the use of amembrane to remove hydrogen sulfide from sour water. Furthermore, thepresent invention does not require a steam-stripping process.

Other methods of removing hydrogen sulfide from water involve using ahigh voltage electrooxidation. U.S. Patent Publication No. 2012/0273367,by Themy et al. (“Themy”) removes hydrogen sulfide by electrooxidation.Themy is incorporated by reference in its entirety.

By way of providing additional background, context, and to furthersatisfy the written description requirements of 35 U.S.C. § 112, thefollowing references are incorporated by reference in their entireties:U.S. Pat. No. 4,218,309 issued to Compton, U.S. Pat. Nos. 4,447,330 and4,536,293 issued to Babineaux, III, Japanese Patent Publication No.2008055291 issued to Mashahiko et al., Chinese Patent No. 101532380issued to Zhengguo; U.S. Pat. No. 8,702,853 to Hebblethwaite entitled,“Tank With Containment Chamber and Gas Scrubber”; U.S. Pat. Publ. No.2016/0010002 to Norling, published Jan. 14, 2016, entitled “FuelCleaning System and Method For a Ship”; U.S. Pat. Pub. No. 2015/0217261to Norling, entitled “Removal of Contaminants from Bunker Oil Fuel,”published Aug. 6, 2015; U.S. Pat. No. 3,255,571 entitled “Method andMeans for Treating Oil Well Emulsions to Walker, issued Jun. 14, 1966;U.S. Pat. Publ. No. 2015/0122125 to Critchfield, entitled “Method ofImproving a Process for the Selective Absorption of Hydrogen Sulfide,published May 7, 2015; U.S. Pat. Publ. No. 2015/0157975 to Critchfield,entitled “Absorbent Composition for the Selective Absorption of HydrogenSulfide”, published Jun. 11, 2015; U.S. Pat. Publ. No. 2015/0360164 toCarruthers, entitled “Absorbent Having Utility for CO2 Capture from GasMixtures” published Dec. 17, 2015; U.S. Pat. No. 9,255,731 to Prim,entitled “Sour NGL Stream Recovery”, issued Feb. 9, 2016; U.S. Pat. No.9,254,453 to McDaniel entitled “Economical Method for ScavengingHydrogen Sulfide in Fluids,” issued Feb. 9, 2016; U.S. Pat. No.5,135,616 to Nicholson, entitled “Oil Purification”, issued Aug. 4,1992; U.S. Pat. No. 8,845,885 to Hassan entitled “Crude OilDesulfurization”, issued Sep. 30, 2014; U.S. Pat. App. Pub. No.2014/0353112 to Hassan, entitled “Crude Oil Desulfurization”, publishedDec. 4, 2014; U.S. Pat. No. 7,523,724 to Duraiswamy, entitled “InTransit Desulfurization of Widely Available Fuels”, issued Apr. 28,2009; U.S. Pat. No. 7,452,405 to Duraiswamy entitled “Multi Stage SulfurRemoval System and Process for an Auxiliary Fuel System”, issued Nov.18, 2008; U.S. Pat. No. 6,539,884 to Husain, entitled “Closed LoopControl of Volatile Organic Compound Emissions from the Tanks of OilTankers, Including as May be Simultaneously Safeguarded from Spillage ofOil By an Underpressure System”, issued Apr. 1, 2003; U.S. Pat. No.4,784,746 to Farcasiu et al., entitled “Crude Oil Upgrading Process”,issued Nov. 15, 1988; U.S. Pat. No. 4,565,620 to Montgomery et al,entitled “Crude Oil Refining”, issued Jan. 21, 1986; U.S. Pat. No.5,733,516 to DeBerry, entitled “Process for Removal of Hydrogen Sulfidefrom a Gas Stream,” issued Mar. 31, 1998; U.S. Pat. No. 6,881,389 toPaulsen et al., entitled “Removal of H₂S and CO₂ from a HydrocarbonFluid Stream,” issued Apr. 19, 2005; U.S. Pat. No. 7,780,933 to Kikkawaet al., entitled “Method of Removing Sulfur Compounds from Natural Gas,”issued Aug. 24, 2010; U.S. Pat. No. 8,187,366 to Yang et al., entitled“Natural Gas Desulfurization,” issued May 29, 2012; U.S. Pat. No.8,465,705 to Ciccarelli et al., entitled “Process for theReduction/Removal of the Concentration of Hydrogen Sulfide Contained inNatural Gas,” issued Jun. 18, 2013; U.S. Pat. App. Pub. No. 2002/0176816to Smith, entitled “In-Line Sulfur Extraction Process,” published Nov.28, 2002; U.S. Pat. App. Pub. No. 2007/0144943 to Lemaire et al.,entitled “Sour Natural Gas Pretreating Method,” published Jun. 28, 2007;U.S. Pat. App. Pub. No. 2008/0172942 to O'Rear et al., entitled“Integration of Sulfur Recovery Process with LNG and/or GTL Processes,”published Jul. 24, 2008; U.S. Pat. App. Pub. No. 2010/0056404 to Talley,entitled “Method for Treating Hydrogen Sulfide-Containing Fluids,”published Mar. 4, 2010; U.S. Pat. App. Pub. No. 2012/0264197 toMitariten, entitled “H₂S Removal from Contaminated Gases,” publishedOct. 18, 2012; U.S. Pat. No. 8,664,462 to Milam et al., entitled “Methodof Processing Feed Streams Containing Hydrogen Sulfide,” issued Mar. 4,2014; U.S. Pat. No. 9,528,062 to Doong et al., entitled “Removal ofSulfur Compounds in an Acid Gas Stream Generated from Solvent-Based GasTreating Process,” issued Dec. 27, 2016; PCT App. Pub. No. 2000/056441to Agarwal et al., entitled “System for Recovery of Sulfur and Hydrogenfrom Sour Gas,” published Sep. 28, 2000; PCT App. Pub. No. 1986/002628to Lynn, entitled “Process for Removal of Hydrogen Sulfide from Gases,”published May 9, 1986; and European Pat. App. Pub. No. 0,033,029 toNicholas et al., entitled “Method of Concentrating and Removing HydrogenSulfide from a Contaminated Gas Mixture,” published Aug. 5, 1981.

One aspect of the present invention is directed to the use of aerationas an effective removal mechanism because hydrogen sulfide exists as adissolved gas in some water. Incidentally, the function of aeration isnot specifically to oxygenate the water; rather it is to strip thedissolved gas (hydrogen sulfide) out of the water by changing theequilibrium conditions of the water and thus drive the dissolved gasout.

The present invention removes hydrogen sulfide from sour water withoutthe need of a chemical catalyst.

In one embodiment, a method for processing bunker oil is disclosed, themethod comprising: filling a first container with water; filling asecond container with bunker oil and water, wherein the crude oilcomprises hydrogen sulfide; distributing air in a first stream from adevice that can create airflow to the first container, using a firstconnection running from the device to the first container, wherein theterminal end of the first connection comprises at least one opening;collecting air in a vapor space located within the first container, thecollected air comprising hydrogen sulfide; transferring the collectedair from the vapor space through an enclosed connection to an aircompartment; distributing air in a second stream from the device to theair using a second connection running from the device to the aircompartment; mixing the second stream and the collected air to form anair mixture; removing the air mixture from the air compartment when theamount of hydrogen sulfide measured is below a desired amount;distributing water from the first container to the second container viaa pumping means; measuring the amount of hydrogen sulfide in the bunkeroil within the second container; continuing to distribute water from thefirst container to the second container until the amount of hydrogensulfide in the bunker oil in the second container is below a desiredamount; returning water from the second container to the firstcontainer; continuing to distribute air in the second stream from thedevice to the first container; and continuing to transfer air from thevapor space from the air compartment; and continuing to measure theamount of hydrogen sulfide in the air mixture wherein the air mixture isremoved when the amount of hydrogen sulfide measured is below a desiredamount.

In another embodiment, a method for removing hydrogen sulfide from anemulsion of water and crude oil is disclosed, the method comprising:receiving, from a well production site, a well production streamcomprising sour gas and sour crude oil; separating the well productionstream into at least sour gas and an emulsion of sour water and souroil, wherein the emulsion comprises hydrogen sulfide; treating theemulsion to remove at least a substantial portion of the hydrogensulfide, the treating comprising: filling a first storage device withwater; filling a second storage device with the emulsion; distributingair in a first stream from a device that can create airflow to the firstcontainer, using a first connection running from the device to the firstcontainer, wherein the terminal end of the first connection comprises atleast one opening; collecting air in a vapor space located within thefirst container, the collected air comprising hydrogen sulfide;transferring the collected air from the vapor space through an enclosedconnection to an air compartment; distributing air in a second streamfrom the device to the air compartment using a second connection runningfrom the device that can create airflow to the air compartment; mixingthe second stream and the collected air to form an air mixture; removingthe air mixture from the air compartment when the amount of hydrogensulfide measured is below a desired amount; distributing water from thefirst container to the second container via a pumping means; measuringthe amount of hydrogen sulfide in the crude oil within the secondcontainer; continuing to distribute water from the first container tothe second container until the amount of hydrogen sulfide in the crudeoil in the second container is below a desired amount; returning waterfrom the second container to the first container; continuing todistribute air in the second stream from the device to the firstcontainer; continuing to transfer air from the vapor space from the aircompartment; and continuing to measure the amount of hydrogen sulfide inthe air mixture wherein the air mixture is removed when the amount ofhydrogen sulfide measured is below a desired amount. In one embodiment,the crude oil is bunker oil.

In some embodiments, the method further comprises: wherein the water isfresh water; wherein the removed air is released to the atmosphere;wherein when the amount of hydrogen sulfide in the crude (or bunker) oilin the second storage device is below a desired amount, transferring thecrude (or bunker oil) out of the second storage device; wherein the(processed) bunker (or crude) oil is transferred to (or transported byor processed within) at least one of a vehicle, a rail car and a ship;maintaining the pH of said water at 7.0 or below; wherein the removedair is stored; wherein the water distributed from the first container tothe second container is distributed at an upper portion of the secondcontainer; and wherein the incoming stream of sour water (or sour crudeoil or bunker oil) is received from a well production site.

In one embodiment, a method for removing hydrogen sulfide from crude oiland water is disclosed, the method comprising: filling a first storagedevice with water; filling a second storage device with crude oil andwater in an equalized amount, wherein the crude oil comprises hydrogensulfide; distributing air from a device that can create airflow to saidfirst storage device, using a first connection running from said devicecreating airflow to said first storage device, wherein the terminal endof said first connection comprises at least one opening; transferringair from vapor space located within said first storage device through anenclosed connection to a separate compartment, wherein the separatecompartment is capable of mixing air; distributing air from said devicethat can create airflow to said separate compartment, using a secondconnection running from said device that can create airflow to saidseparate air mixing compartment; measuring the amount of hydrogensulfide in said separate air storage compartment; releasing air fromsaid air storage compartment when the amount of hydrogen sulfidemeasured is below a desired amount; distributing water from said firststorage device to said second storage device via a pumping means,wherein the water from said first storage device enters said secondstorage device through the top of said second storage device; measuringthe amount of hydrogen sulfide in the crude oil within said secondstorage device; continuing to distribute water from said first storagedevice to said second storage device until the amount of hydrogensulfide in the crude oil in said second storage device is below adesired amount; returning water from said second storage device to saidfirst storage device; continuing to distribute air from said device thatcan create airflow to said first storage device; continuing to transferair from said vapor space from said first storage device to saidseparate air mixing compartment; and continuing to measure the amount ofhydrogen sulfide in said separate air mixing compartment, wherein air isreleased from said separate air mixing compartment when the amount ofhydrogen sulfide measured is below a desired amount, and wherein saidmethod is devoid of any chemical catalysts or chemical scavengers beingemployed to remove hydrogen sulfide.

In some embodiments, the method or system further comprises: wherein thefirst storage device is filled with water comprising hydrogen sulfide,and wherein the water is fresh water.

In another embodiment, a method for removing hydrogen sulfide from crudeoil without the use of catalysts or chemical scavengers is disclosed,the method comprising: a) providing a first container adapted to holdcrude oil, said first container having an inlet and an outlet; b)providing a desired amount of crude oil into said first container at anatmospheric pressure, said crude oil having a first concentration ofhydrogen sulfide; c) contacting the crude oil inside said firstcontainer with water entering said first container through said inlet,the water having a first amount of hydrogen sulfide; and d) transferringwater out of said first container through said outlet to generate astream of water, said stream of water having more hydrogen sulfide thansaid water entering said first container; e) providing a secondcontainer adapted to hold water, wherein said second container furthercomprises a first inlet, a first outlet, and a second outlet; f) fillingsaid second container with water to a level sufficient to provide avapor space at a top surface of the water through said first inlet withwater from said outlet of said first container; g) bubbling air into thewater inside said second container; h) transferring hydrogen sulfidefrom said vapor space through said first outlet in said second containerto form a hydrogen sulfide gas containing stream; i) providing air tosaid hydrogen sulfide gas containing stream to generate a second dilutedhydrogen sulfide gas containing stream; and j) transferring water fromsaid second container through said second outlet and into the inlet ofsaid first container; wherein said method is devoid of any chemicalcatalysts or chemical scavengers being employed to remove hydrogensulfide.

In some embodiments, the method or system further comprises: whereinafter said transferring step, the crude oil in said first container hasa reduced concentration of hydrogen sulfide as compared to said firstconcentration; maintaining the pH of said water at 7.0 or below;performing said method at a temperature of at least 45 degreesFahrenheit; measuring the amount of hydrogen sulfide present in saidcrude oil after said contacting step c); where the contacting step c) isperformed at a rate from 20 gallons per minute to 8400 gallons perminute; repeating step c) until the amount of hydrogen sulfide in saidcrude oil is reduced to an amount below 100 parts per million; releasinginto the ambient environment the second diluted hydrogen sulfide gascontaining stream when the concentration of hydrogen sulfide present insaid second diluted hydrogen gas containing stream is below apredetermined level; wherein step j) of transferring is conducted at arate from 20 gallons per minute to 8400 gallons per minute; wherein stepg) of bubbling is conducted at a rate of at least 105 standard cubicfeet per minute; wherein contacting said crude oil with water furthercomprises agitating said crude oil; measuring the concentration ofhydrogen sulfide present in the second diluted hydrogen sulfide gascontaining stream and releasing into the ambient environment the seconddiluted hydrogen sulfide gas containing stream when the concentration ofhydrogen sulfide is measured below a predetermined level; repeatingsteps c-j until the concentration of hydrogen sulfide in said crude oilis reduced to 100 parts per million or below; repeating steps h-i untilthe concentration of hydrogen sulfide present in said second dilutedhydrogen sulfide containing stream is below a predetermined level;maintaining the pH of said water at 7.0 or below; performing said methodat a temperature of at least 45 degrees Fahrenheit.

In another embodiment, a method for removing hydrogen sulfide from crudeoil and water comprises: a) providing a first container adapted to holdwater, said first container comprising an aperture, an inlet, and anoutlet; b) providing said first container with water sufficient toprovide a vapor space between a top surface of the water and saidaperture, wherein said water has a pH of 7.0 or below; c) providing asecond container, said second container adapted to hold crude oil, andhaving an inlet and an outlet and having an atmospheric pressure; d)providing said second container with an amount of sour crude oil,wherein said sour crude oil has not been treated by a treatment selectedfrom the group consisting of: hydrotreatment, chemical scavengertreatment, and chemical catalyst treatment; e) bubbling air through thewater contained within said first container to produce a first mixed airfaction in said vapor space; f) transferring said first mixed airfaction from said first vapor space through said aperture to a mixingair station to produce a second mixed air faction; g) providing air tosaid mixing air station; h) releasing air from said mixing air stationwhen the concentration of hydrogen sulfide present in said second mixedair faction is below a predetermined amount; i) conveying water fromsaid first container to said second container at a rate from 20 gallonsper minute to 8400 gallons per minute, whereby said water stripshydrogen sulfide from said crude oil as the water contacts said crudeoil, generating a stream of sour water; j) conveying said sour waterthrough said outlet of said second container and into said firstcontainer; k) repeating step i) until the amount of hydrogen sulfide insaid sour crude oil is reduced to a predetermined level; and l)repeating steps e-h until the concentration of hydrogen sulfide from thewater conveyed to said first container is reduced to a predeterminedlevel.

In another embodiment, a method for removing hydrogen sulfide from crudeoil and water comprises: filling a first storage device with water;filling a second storage device with crude oil and water in an equalizedamount, wherein the crude oil comprises hydrogen sulfide; distributingair from a device that can create airflow to said first storage device,using a first connection running from said device creating airflow tosaid first storage device, wherein the terminal end of said firstconnection comprises at least one opening; transferring air from vaporspace located within said first storage device through an enclosedconnection to a separate compartment, wherein the separate compartmentis capable of mixing air; distributing air from said device that cancreate airflow to said separate compartment, using a second connectionrunning from said device that can create airflow to said separate airmixing compartment; measuring the amount of hydrogen sulfide in saidseparate air storage compartment; releasing air from said air storagecompartment when the amount of hydrogen sulfide measured is below adesired amount; distributing water from said first storage device tosaid second storage device via a pumping means, wherein the water fromsaid first storage device enters said second storage device through thetop of said second storage device; measuring the amount of hydrogensulfide in the crude oil within said second storage device; continuingto distribute water from said first storage device to said secondstorage device until the amount of hydrogen sulfide in the crude oil insaid second storage device is below a desired amount; returning waterfrom said second storage device to said first storage device; continuingto distribute air from said device that can create airflow to said firststorage device; continuing to transfer air from said vapor space fromsaid first storage device to said separate air mixing compartment; andcontinuing to measure the amount of hydrogen sulfide in said separateair mixing compartment, wherein air is released from said separate airmixing compartment when the amount of hydrogen sulfide measured is belowa desired amount.

In certain embodiments, the invention comprises an air source, a tank, aplurality of lines that distribute air from the air source to the tankand a vent stack, connections that distribute the air from the airsource into the tank, a hydrogen sulfide monitor, and a vent stackconnected to the water tank and air source. The air from the air sourceruns to a tank filled with sour water through an airflow line. Theairflow line is connected to a pipe with at least one hole. The pipe isin the water tank. A second line runs to the vent stack through a secondairflow line. In certain embodiments, air flows to the vent stack at arate of 120 standard cubic feet per minute (“scf/m”). The airflow may beadjusted incrementally every hour for twelve hours. The air distributionratio may be adjusted hourly until the ratio of airflow to the watertank line increases to about 120 scf/m and the airflow to the vent stackdecreases to about 20 scf/m. The amount of hydrogen sulfide is measurednear the top of the vent stack. The air with the acceptable levels ofhydrogen sulfide is then vented. The plurality of lines running from theair source are secured by typical ways known to those skilled in the artto connect air lines to air source. Embodiments of the present inventionensure that any materials containing hydrogen sulfide are enclosedwithin the invention and not exposed to the outside environment. Asthose skilled in the art will recognize, the air source can be any airsource able to generate air, such as a compressor or a blower.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of the specification, illustrate embodiments of the invention and,together with the general description of the invention given above andthe detailed description of the drawings given below, serve to explainthe principals of this invention.

In certain instances, details that are not necessary for anunderstanding of the disclosure or that render other details difficultto perceive may have been omitted. Further, the drawings of the systemand/or method do not detail all features of the system and/or method,and do not show the entire system and/or method. It should beunderstood, of course, that the disclosure is not necessarily limited tothe particular embodiments illustrated herein.

FIG. 1 depicts processing of crude oil, according to one embodiment ofthe system;

FIG. 2 depicts processing of crude oil, according to another embodimentof the system;

FIG. 3 depicts one embodiment of a subsystem of FIG. 1 or 2 to removehydrogen sulfide from oil and water;

FIG. 4 depicts another embodiment of a subsystem of FIG. 1 or 2 toremove hydrogen sulfide from oil and water;

FIG. 5 depicts certain embodiments of the invention that use a commoncontainment vessel;

FIG. 6 depicts certain embodiments of air injection of an embodiment ofthe subsystem of FIG. 1 or 2 to remove hydrogen sulfide from oil andwater; and

FIG. 7 depicts one embodiment of a system for sulfur reduction or sulfurremoval.

FIG. 8 depicts certain embodiments of the invention comprising apressurized sample.

The drawings are not necessarily to scale. In certain instances, detailsthat are not necessary for an understanding of the invention or thatrender other details difficult to perceive may have been omitted. Itshould be understood, of course, that the invention is not necessarilylimited to the particular embodiments illustrated herein.

To assist in the understanding of the present invention the followinglist of components and associated numbering found in the drawings isprovided herein:

# Component 1 System 2 First subsystem 3 Second subsystem 4 System input5 First stream 6 Second stream 10 Sour water container 11 Air compressor12 Cap assembly element 13 Line 14 Air dispenser bar 15 Vapor space air16 Vent stack 17 Air distribution line 18 Meter gauge 19 Line 20Distribution pump 21 Line 22 Attaching line 23 Sour oil container 24Second line 26 Water pump 27 Automation cabinet 28 Air source 29 Storagerack 30 Single vessel 31 Trailer 32 Partition 34 Aperture 41 Pump 42Well head 43 Well head line 44 Site tank farm 45 Site tank farm line 46Offsite tank farm 47 Offsite tank farm line 50 Treater/separator 52Separated gas line 53 Converter 54 Treater/separator line 55 Pneumaticsignal 60 Gas distribution 62 Sweetened Oil line 70 Vehicle 72 Rail 74Ship 76 Pipeline 80 Sulfur removal system 1100 Air compressor or airpump 9025 Air line 9050 Water stripping reservoir 9100 Connection 9150High-pressure low-volume pump 9200 Relief regulator 9250 Connection 9300Pressurized oil sample container 9350 Element 9400 Water samplecontainer 9500 Liquid pressure regulator h Depth height

DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS OF THE INVENTION

FIG. 1 depicts processing of crude oil, according to one embodiment ofthe system. Generally, the system 1 comprises first subsystem 2 andsecond subsystem 3. First subsystem 2 receives system input 4 (e.g.crude oil) and processes system input 4 as first-stage processing withinfirst subsystem 2. First subsystem 2 outputs first stream 5, which isoutput to and received by second subsystem 3. Second subsystem 3 outputssecond stream 6.

First-stage processing of first subsystem 2 may comprise varying levelsof processing, comprising heating as typically performed in oilrefineries. Such processing may include heating in, for example, aseparator and/or a heater/boiler to separate crude oil components, suchas natural gas liquids, naphtha, gasoline, kerosene, light gas oil(diesel), lubricating oil, heavy gas oil and bottoms (e.g. bitumen). Inone embodiment, first-stage processing of first subsystem 2 outputs orproduces bunker oil as first stream 5. In one embodiment, first-stageprocessing of first subsystem 2 outputs or produces sour oil as firststream 5. a system and method are disclosed wherein crude oil isprocessed in a first subsystem, such as a separator and/or heater, toseparate oil components. The first subsystem may provide a stream ofbunker oil to a second subsystem, wherein hydrogen sulfide is removedfrom the separated bunker oil.

FIG. 2 depicts processing of crude oil, according to another embodimentof the system. More specifically, FIG. 2 depicts certain embodiments ofthe invention as part of an overall hydrocarbon recovery, processing andtransportation system 40. (Here, system 40 is akin to system 1, andseparator 50 is akin to first subsystem 2). A well head 42 produces amixture of hydrocarbon (i.e. sour oil), water and gas, shown as wellhead line 43. In relation to FIG. 1 , the well head 42 produces systeminput 4. Well head line 43 and enters treater or separator (analogous to“first-stage processing” in first subsystem 2 depicted in FIG. 1 ) toseparate the oil, water, and gas components in any of several knownways. For example, a three-phase separator would separate oil, water andgas, or a 2-phase separator may separate gas from an oil and wateremulsion. Such separators are known in the art. In many separators 50,gas separated is sent, via separated gas line 52, for gas distribution60. Gas distribution 60 may comprise collection, flaring, treating,on-site use for e.g. on-site devices to include vehicles, andstoring/selling. Separator 50 outputs treater/separator line 54comprising sour oil and/or an emulsion of sour oil sour water to secondsubsystem 3 of the invention (as described above) treater/separator line54, and/or sweetened oil line 62, may be joined with other sources ofsour oil and/or emulsions of sour oil sour water, comprising site tankfarm 44 sources via site tank farm line 45, and off-site tank farm 46sources via off-site tank farm line 47. (Line 54 may comprise bunkeroil, and may comprise bunker oil as treated or processed as describedabove or elsewhere in this disclosure). Note that line 54 may alsoreturn oil and water and/or a water/oil emission to one or both of sitetank farm 44 and off-site tank farm 46. Also, note that sweetened oilline 62 may receive and/or output to one or both of site tank farm line45 and off-site tank farm 46. Finally, one or both of site tank farmline 45 and off-site tank farm 46, if more broadly used for any mannerof liquid storage, may also interconnect or communicate with othercomponents of system 40, comprising well head 40, treater/separator 50,subsystem 3, and vehicle 70, rail 72, ship 74 and pipeline 76.

Subsystem 3 outputs sweetened oil at sweetened oil line 62 and deliversthe sweetened oil to one or more recipients, comprising vehicles 70 suchas semi-tractor trailers e.g. oil trucks, rail cars 72 or railroadreceiver systems, nautical ships or nautical receiver systems 74 andpipelines 76.

In certain embodiments, the system 40 comprises “second stageseparators” or “gas boots” which serve to allow additional gas to bereleased from liquids before tankage. For instance, if, for example,element 2, 50 operates at 31 psi, the second stage separator mightoperate at 16 psi. With some shale production curves falling quicklyfrom 5000 BOPD (bbls oil per day) to 800 BOPD, these intermediatevessels allow the site to operate safely and send less gassy oil totransportation—without the expense of placing a larger treater ormultiple treaters, which cost more than the second stage vessels.

In certain embodiments, the system 40 is scaled to be used at a“transload” facility—that is, a pipeline terminal or truck terminalwhich receives oil of all description and blends it, then loads trainswith the oil or sends the oil down other pipelines. One motivation forsuch blending is to lower the H₂S concentration that would otherwiseexist in some batches if not blended with lower ₂S-concentration oil. ₂Sconcentrations in North Dakota, for instance, are reaching a point whereblending might not suffice.

FIG. 3 provides a diagram depicting certain embodiments of the inventionrelated to a subsystem 3 to remove hydrogen sulfide in water and oil.Element 10 is a container comprising sour water. Element 11 is an aircompressor used to distribute air to elements 10 and 16. Element 17 is aline from element 11 to distribute air to element 10, sealed by a capassembly, element 12. Element 13 is a line running from cap assemblyelement 12 to an air dispenser bar. Element 14 is an air dispenser bar.Element 14 is submerged in the sour water located in element 10. Inalternate embodiments, air dispenser bar 14 is disposed in any locationwithin the container 10, to include the center portion and the upperportion of container 10. The air in the vapor space is transferred byelement 15 to a vent stack, element 16. Element 24 is a second linerunning from element 11 to element 16, where air from the air compressordilutes air transferred from the vapor space to the vent stack. Element18 is a gauge that meters the amount of hydrogen sulfide in element 16.The air in the vent stack 16 may be distributed in any of several ways,comprising release to the atmosphere, flaring i.e. burning, andcapturing for storage, transport or sale. Also, the vent stack 16assembly could be modified or substituted to include the further sulfurprocessing, e.g. a sulfur reduction/removal system (see, e.g., FIG. 7and associated description.)

Element 23 is a container comprising sour oil and water. The oil andwater in element 23 are equalized. Element 19 is a line from element 10to element 20. Element 20 is a pump that distributes lean water fromelement 10 to element 23. Element 20 pumps the water through element 21,a line running from element 20 to the top of element 23. In alternateembodiments, line 21 emits water to other than the top of element 23,e.g. from the bottom or side of element 23 (see, e.g. FIG. 7 andassociated description.) In alternate embodiments, the oil and water inelement 23 are not equalized.

As the water is pumped into element 23, it passes through the sour oildue to a lower specific gravity. As the water travels through the souroil, it obtains hydrogen sulfide from the oil, thus removing hydrogensulfide from the oil. The water then returns to element 10 throughelement 22. Element 22 is a line attaching element 23 to element 10. Thewater runs from element 23 to element 10 via hydrostatic pressure. Inalternate embodiments, the water runs from element 23 to element 10 viaother than hydrostatic pressure, e.g. via one or more pumps. Hydrogensulfide is removed from the water that returns from element 23 asdescribed above. Those skilled in the art can appreciate that thespecific elements in the embodiment depicted in this figure areconnected using typical connections known to those skilled in the art,such as the appropriate seals, caps, clamps, tubes, O-rings, splittervalves, etc. An important aspect of the present invention is that nospecialized equipment is necessary, and the items used are those readilyavailable to those skilled in the art.

In one embodiment, certain embodiments of the invention that are mobile.For example, a commercially-available trailer, to include thoseconventionally found on hydrocarbon production sites, may transport ordomicile components of the system.

In another embodiment, the subsystem 3 of FIG. 3 is configured to removehydrogen sulfide from water without coupling to a system to removehydrogen sulfide from oil. Element 10 is a container comprising sourwater. Element 11 is an air compressor used to distribute air to element10. Element 17 is a line from element 11 to distribute air to element10, sealed by a cap assembly, element 12. Element 12 is secured toelements 11 and 17 using typical items known to those skilled in theart. Element 13 is a line running from cap assembly element 12 to an airdispenser bar, element 14. Elements 12, 13, and 14 are attached usingtypical means known to those skilled in the art. Element 14 is submergedin the sour water located in element 10. In alternate embodiments, airdispenser bar 14 is disposed in any location within the container 10, toinclude the center portion and the upper portion of container 10. Theair in the vapor space is transferred by element 15 to a vent stack,element 16. Element 24 is a second line running from element 11 runs toelement 16, where air from the air compressor dilutes air transferredfrom the vapor space to the vent stack. Element 18 is a gauge thatmeters the amount of hydrogen sulfide concentration in element 16. Inone alternate embodiment, container or tank or storage vessel 10 is acommercially available tank, to include those of rail cars and trucktanks, and any of standard field tanks, to include both low profile(generally equal or less than 16 feet in height) and high-profile tanks(generally those greater than 16 feet in height). The air in the ventstack 16 may be distributed in any of several ways, comprising releaseto the atmosphere, flaring i.e. burning, and capturing for storage,transport or sale. Also, the vent stack 16 assembly could be modified orsubstituted to include the further sulfur processing, e.g. a sulfurreduction/removal system.

The subsystem 3 of FIG. 3 enables re-cycling of production sour waterwhich, when sweetened, may be reused in well production or be depositedon-site for irrigation or other purposes. In one example use, thesweetened water of subsystem 3 may be used as part of ahydraulic-fracturing (i.e. “fracking”) operation to remove H2S fromfracking blowback water, wherein the treated water may be re-used forfracking or other production uses or disposed of by means which prohibitH2S.

In one embodiment of second subsystem 3, the subsystem 3 is configuredto remove hydrogen sulfide from oil without coupling to a system toremove hydrogen sulfide from water. Such a configuration of subsystem 3would require a supply of water substantially free of H2S (to input asline 21 to a tank 23 of sour oil) and a means to dispose of sour water(as output as line 22) from the tank 23.

FIG. 4 depicts another embodiment of a subsystem of FIG. 1 or 2 toremove hydrogen sulfide from oil and water. FIG. 4 provides a diagramdepicting certain embodiments of the invention comprising an I to Pconverter that regulates air flow to a plurality of air lines. Aircompressor, element 11 is connected to element 17, a line running air toa tank containing sour water and element 24, a line running air to avent stack. Element 55 is connected to element 53 by element 54. Element53 converts an electrical signal from element 55 into a pneumaticsignal. The signal from element 53 is relayed by element 52 to elements50 and 51. Based on the input signal from element 53, element 50 mayincrease or decrease the amount of air flowing through element 17. Basedon the input signal from element 53, element 51 may increase or decreasethe amount of air flowing through element 24. Although this diagramdepicts a preferred embodiment, other variations to this embodiment,such as using a plurality of I to P converters may be used and is withinthe spirit of the present invention.

In certain embodiments, the water may enter the sour water container 23via line element 21 by other than the top of the container, e.g. fromthe side or bottom of the container. For example, the water entering thetank 23 from line 21 may enter the tank 23 at any vertical locationalong the tank 23 and at the bottom the tank 23. In some configurations,one or more pumps, such as the pump 20, are employed to deliver water totank 23.

In certain embodiments, the water provided to tank 23 is by any means soas to provide or maintain a circulation of water at an interface withthe sour oil in tank 23. Stated another way, any means of circulatingwater from the water sweetening tank through to the oil sweetening tankand then back into the water sweetening tank may be implemented. Inanother embodiment, the water provided to the tank 23 may interface withthe sour oil such that the water moves vertically or rolls so as to keepthe oil/water interface as fresh as possible. In another embodiment, thewater rotates on a horizontal plane. In another example, the tank 23employs mixers comprising agitators, baffles and similar devices knownto those skilled in the art to mix the water and the sour oil.

In one embodiment, in addition to water, oil is circulated through thetank 23. In one embodiment, the only fluid circulated through subsystem3 is water.

In one embodiment, the size configuration, and quantity of tanks isvaried. FIG. 1 depicts an embodiment having one oil sweetening tank 23and one water sweetening tank 10. Alternatively or additionally,intermediate vessels using internals (e.g. trays, loops and/or baffles)are employed.

In one embodiment, the subsystem 3 employs tanks 10, 23 of any size suchthat the height of each tank (i.e. each of tanks 10 and 23, and tank 30of FIG. 5 ) in the process is equal. In one embodiment, tank 23 is a1000 bbl tank (for oil sweetening) and tank 10 is a 400 bbl tank (forwater sweetening) and vice versa, such that each tank is of the sameheight, or of heights that allowed the levels required in each tank tobe maintained. Tanks 10, 23, 30 may comprise upright cylindrical tanks,horizontal cylindrical tanks, spherical tanks and any manner ofrectangular tank(s) and those known to one skilled in the art. In oneembodiment, one or more of tanks 10, 23, 30 are commercially availabletanks as typically used in the hydrocarbon industry, comprising a 400bbl, nominally 12′×20′, upright cylindrical tank. In one embodiment,tanks 10, 23, 30 are any tanks capable of holding liquid and sealablewith standard 4 oz or 8 oz pressure and vacuum hatches. (These areuniversally called “atmospheric vessels” in that they are made towithstand the hydrostatic weight of liquids and a slight pressure orvacuum at the top, i.e. a vapor space.) In one embodiment, one or moreof tanks 10, 23, 30 comprise any tank constructed and rated for morepressure and/or vacuum.

In one embodiment, the subsystem 3 (e.g. of FIG. 3 ) operates atsubstantially atmospheric pressure. It has been found that operatingsubsystem 3 above nominally atmospheric pressure, in some configurationsor embodiments, inhibits the transfer of H₂S.

In certain embodiments, the subsystem 3 (e.g. of FIG. 3 ) is a hybridsystem in that it includes fluids other than water and crude oil. In oneembodiment, the method may use a small amount of liquid surfactant, suchas various types of alcohol. Any small amount (1 gallon or less per 300bbls of water used) of liquid surfactant that is known to “water-wet”microscopic solids is employed. Although the liquid surfactant is notrequired, the use of a liquid surfactant allows re-use of the same watercontinuously, nominally indefinitely, without accumulating oil-wetmicroscopic solids on the oil/water interface in the oil sweeteningtank. Such potential solids, if allowed to accumulate at that interface,may inhibit H2S transfer from rich-oil to lean-water. In one embodiment,less than one (1) gallon of household-grade Isopropyl Alcohol (rubbingalcohol) is employed, and/or ethanol and methanol. Commercial productsknown to “water wet” microscopic solids may additionally oralternatively be used. Such additives are added when needed, asdetermined by sampling the oil-water interface in the oil sweeteningtank with a “tank thief” or any other device capable of obtaining arepresentative sample of that interface (the sample being equal partscrude oil and water.) Also, simple visual inspection will indicatewhether microscopic solids have collected on the interface and thus maymotivate a need for such additives. In one embodiment, volumes ofapproximately between one (1) and two (2) quarts of additive areemployed.

In certain embodiments, scavengers may be used, to, for example,minimize processing time of one or both of the processing of sour oil tosweetened oil and sour water to sweet water. In particular, to minimizeprocess slow-down during the approximately last 10-20% of processingduration (where processing duration is time to convert sour oil to adefined level of sweetened oil and/or duration of time to convert sourwater to a defined level of sweet water), a scavenger may be used. Insuch embodiments, a small amount of H2S scavenger liquid is provided toone or both of tank 10 and tank 23. The use of scavengers must be,however, balanced against a possible increase in PH level with somescavengers.

In certain embodiments, chemicals that readily capture H₂S, ascommercially available, are added to the method to, for example,increase method efficiencies such as reducing processing durations.

In certain embodiments, the method provides a chemical-free sweeteningprocess that treats sour water for reuse in well servicing, productiondevices and/or for disposal. In certain embodiments, the method removesH₂S without introducing any chemicals into the production (e.g. from thewell head) thereby leaving no converted sulfides after treatment. Incertain embodiments, the method prevents or retards or mitigateschemical overtreatment or under-treatment in sweetening operations. Incertain embodiments, the method removes hydrogen sulfide (H₂S) from souroil, sour water, sour water/sour oil condensate and/or condensate. Incertain embodiments, the method takes treated (i.e. sweetened) water andapplies the treated water to the production site, e.g. for use in theproduction well e.g. for fracking. In certain embodiments, the methodprevents or reduces or mitigates cross-contamination of wells and/orproduction site. In certain embodiments, the method may handle highconcentrations of H₂S and/or low concentrations of H₂S. In certainembodiments, the sweetened water produced is transported to storagetanks and/or placed back online.

In certain embodiments, PH modifiers are employed. In some embodiments,the system and/or method (throughout this disclosure, any reference tothe system of the invention also applies to the method and/or process,and vice versa) operates at a PH at or below 7. In some embodiments, thesystem operates at a PH between 1 and 7. In some embodiments, to modifythe water PH downward, various acids or other low-PH materials may beused. Care should be taken to use acidic additives of such low strengthper volume that they do not endanger humans or property or theenvironment in their transportation and use. Acidic additives maycomprise low strength hydrochloric acid, vinegar and lemon juice, andany acidic additives known to those skilled in the art.

In certain embodiments, salts may be added. Generally, in someembodiments, water with various heavier salt(s) content is beneficial tothe process in that salts provide a cleaner oil/water interface in theoil sweetening tank. In some embodiments, the method may use watercomprising fresh water, salt water and any water type wherein the oilbeing sweetened may float upon it. Generally, in some embodiments, thesystem employs water from the same formation(s) and wells from which theoil being treated originates; such water has been found in someembodiments to optimize (e.g. increase efficiencies such as reducingprocessing times) the process.

In certain embodiments, the method operates at ambient temperature. Inother embodiments, warmer (than ambient) temperatures are used, which toa threshold limit, sweetens faster, although causes more hydrocarbonvapors to be vented from the oil sweetening tank. Any gaseous componentventing from the oil sweetening tank, by definition, lowers the volumeof that oil. For this reason, an optimal water temperature range isdecided upon weighing shortening of treating times against oil volumeloss. In winter in cold climates, water may need to be heated prior toprocess start to ensure that the water used does not freeze before theprocess is finished. In one embodiment, anti-freeze chemical components(other than various salts) may be added to the water.

In certain embodiments, the water sweetening tank 10 and the oilsweetening tank 23 (or the levels on each side of partition 32 of singlevessel 30 configuration of FIG. 6 ) are not at the same level, i.e. notsharing a common bottom plane so as to allow use of hydrostatic pressure(aka gravity feed or gravity equalization) to send the now-H2S-richwater from the oil sweetening tank back to the water sweetening tank asdepicted in FIG. 1 . In such embodiments, additional pumps or similarmeans are employed to pump or move fluid that otherwise was moved viahydrostatic pressure and automated leveling controls are employed on thetank(s) involved. In such embodiments, tank geometries, such as heightand width would not need to be equal.

In certain embodiments, no automation is used, e.g. to control pumpingvolumes and/or tank relative or absolute heights. In certainembodiments, with proper sizing of pump(s), the entire method couldoperate manually without any form of automation or controls.

In certain embodiments, tanks 10, 23, 30 comprise any tank or pressurevessel that at minimum may hold atmospheric pressure and/or theassociated hydrostatic head (and any dynamic loading of the fluidcontainer within) of the contained fluid. Vessels of higher pressurerating may also be used, as well as rail tank cars and sea-bornecontainment vessels.

In certain embodiments, no steam is used. In some embodiments, the waterused is not heated or provided above 110 degrees Fahrenheit. In someembodiments, the water is initially supplied at higher temperature (e.g.to a maximum of 110 degrees F.) in very cold outside temperatures toprovide a nominal minimal temperature (e.g. 60 degrees F.) for theduration of the sweetening process.

FIG. 5 depicts certain embodiments of the invention that use a commoncontainment vessel. Single vessel 30 comprises partition 32 and aperture34. Partition separates sour water tank 10 from sour oil tank 23. Such asingle vessel 30 would generally replace separate tanks 10 and 23 ofearlier embodiments, e.g. that of FIG. 1 , and engage with othercomponents of subsystem 3 (e.g. of FIG. 3 ) such as line 21 supplyingwater from tank portion 10 to tank portion 23. Stated another way, allother lines, pumps, compressors or blowers and line entry points intosides of the vessel would be similar or identical to those in thetwo-tank system (e.g. of FIG. 1 ), but with added care to be sure no airintroduced into the water sweetening side gets into the pump line goingto the oil sweetening side. In one configuration, the aperture 34 is aslot at the bottom of the barrier or partition 32, although otherconfigurations are possible, to include circular apertures or anyconfiguration that enables a water rate powered by gravity (weight,hydrostatic pressure) to comfortably exceed that which is pumped intothat side of the vessel as H2S-lean water and that prevents air from thewater side into the oil side. Note that the line 22 (of FIG. 1 ), whichin above configurations (i.e. those with two physically separate tanks)sends H2S-rich water from the bottom of the oil sweetening tank to thewater sweetening tank, would be fully replaced by the opening (aperture34) in the bottom of the partition 32.

In certain embodiments, the system employs large loops of large diameterpipe instead of tanks.

In certain embodiments, the system employs a non-contained water sourcesuch as a lake, ocean, or river, a water well or any source of non-H₂Swater. In one embodiment, the system disposes of H₂S-rich water down asour water disposal well.

FIG. 6 depicts certain embodiments of air injection of an embodiment ofthe subsystem of FIG. 1 or 2 to remove hydrogen sulfide from oil andwater. Specifically, FIG. 6 depicts alternate embodiments of airinjection (aka the air line) into sour water tank 10. Generally, one ormore pipes or tubes may enter vessel or tank 10, each capped with capassembly element 12, so as to deliver air via element 14. As such, theair dispenser bar 14 may terminate in a straight pipe run, or an elbowrun, as depicted in FIG. 7 . The terminus of the air line (i.e. element14) may be required to be at or below a threshold depth height h fromthe surface of the water, such as, in a preferred embodiment, at orgreater than 0.5 feet, in a more preferred embodiment, at or greaterthan 1 foot. In some embodiments, the air line enters the tank 10 at anypoint on the top, bottom or sides of the tank. Note that an air linethat enters the tank at the top and then releasing air fairly shallowinto the water column allows a lower pressure blower or compressor to beused to provide the air; this is because if that air line comes in atthe bottom, even if it terminates and releases air 6 inches beneath thesurface, it can fill with water between batches, thereby requiring thecompressor or blower to overcome the full hydrostatic weight of thewater column in order to start injecting air.

In certain embodiments, the air line may be equipped with flapper-typecheck valves. In certain embodiments, the air line may terminate insidethe tank (the point where the air is injected into the water) openended, or with a “disperser” consisting of several holes. If there is adisperser, the sum of the area of the holes may equal or exceed the areaof the same line (pipe, hose) open ended. If open ended, the line mayterminate in a downward direction. If a disperser end is used, that canbe oriented in any way convenient—up, down, horizontally. In certainembodiments, the air line from the compressor or blower may be ofsufficient size as to not create undue back-pressure on the compressoror blower, as this artificial backpressure wastes energy.

In some embodiments, a compressor or blower with a 10-30 standard cubicfeet per minute (SCFM) flow rate will be fitted to a 1.5-inch interiordiameter (ID) air line. In some embodiments, a compressor or blower witha 30-65 standard cubic feet per minute (SCFM) flow rate will be fittedto a 2.0-inch interior diameter (ID) air line. In some embodiments, acompressor or blower with a 65-130 standard cubic feet per minute (SCFM)flow rate will be fitted to a 2.5-inch interior diameter (ID) air line.In some embodiments, the sum of the areas of the holes in any disperserarrangement may meet or exceed the areas of these lines. Generally,larger volumes of air flow, as would be used in greatly scaled upversions of the method, will require the air line from the compressor orblower to be sized such that it does not create undue back-pressure onthe compressor or blower.

In some embodiments, the air may be injected as far from the wateroutlet to the pump as possible. In one embodiment, this may be 180degrees on a circular tank or on the opposite wall on a rectangulartank. If the tank has a longer horizontal dimension, the air injectionpoint and the outlet to the pump may be opposite on or near a linebisecting that longer dimension. Generally, the air should be injectedat a point that minimizes the likelihood that injected air may circulateas bubbles to the line going to the pump. In one embodiment, devices ormethods are employed to prevent air out of the vapor space above the oilin the oil sweetening tank 23, to include using a cavitation vent.

FIG. 7 depicts another embodiment of a subsystem of FIGS. 1 and 2 forsulfur reduction or sulfur removal system. More specifically, FIG. 7depicts certain embodiments of a sulfur removal system 80. The processfits or integrates with the above embodiments, e.g. that shown in FIG. 1, by replacing the flare stack. The system 80 receives air from vaporspace as element 15. Dilution (line 24) in system 80 would only be usedto create a vacuum on the left side of FIG. 7 to reduce backpressure onthe system. In that the total stream is cooled significantly by the timeit reaches the left side of FIG. 7 , a fan placed in the pipe a shortway from the end may serve better, thereby reducing the size of thecompressor or blower in FIG. 1 .

The process of FIG. 7 brings the entire air flow on the exhaust end ofthe baseline process (the H2S-rich exhaust coming from the waterstripping tank) up to a temperature between 900 and 1400 degreesFahrenheit. This incineration converts all the H2S to SO2 (sulfurdioxide). Waste heat downstream of incineration is then used to createsteam (in a steam jacket external of the incineration pipe) from a smallamount of fresh water (water new to the system). This steam is injecteda short distance downstream of where it is created, into theincineration pipe. The steam quickly grabs the SO2 (although not theH2S, as there is no H2S left at this stage). The air and S02-rich steamare then cooled to the point that the steam condenses to water. Statedanother way, the system makes it rain inside the pipe. (Rain is an aptdescription here because it is what is commonly known as “acid rain”,the SO2 having been converted to sulfuric acid in water.) Note that theacid rain is captured and confined, and not releases into theenvironment, as occurs when H2S is flared directly. The acidic water iscollected. The remaining (now sulfur-free or very sulfur-reduced) air isvented to atmosphere. The acidic water may then be 1) used in theprevious process to keep the water PH low, which is essential forefficiency, or 2) treated with a small amount of soda ash (or otherinexpensive base) and safely disposed of into common, non-sour waterdisposal wells.

FIG. 8 provides a diagram for certain embodiments that comprise ahigh-pressure low-volume water pump to circulate stripped water througha sample to remove hydrogen sulfide. The embodiment comprises an aircompressor or air pump 1100 (e.g. a Coralife SL-381.3 scfm pump), awater stripping reservoir 9050 (e.g. a plastic or metal vessel having acapacity of between about five liters and about ten liters), ahigh-pressure low-volume pump 9150 (e.g. a pneumatic pump or electricpump such as a Texsteam 5000 series pump), a relief regulator 9200, apressurized oil sample container 9300 (e.g. a container having acapacity of about one liter and adapted to be pressurized to at leastabout 75 psi), a water sample container 9400 (e.g. a container having acapacity of about one liter), and optionally a liquid pressure regulator9500. Upon system initialization or startup, the water strippingreservoir 9050 is mostly but less than completely filled (e.g. filled tobetween about five eighths of capacity and about three quarters ofcapacity) with distilled water, then receives water to be stripped fromthe water sample container 9400 during operation of the system. Inoperation, the air compressor or air pump 1100 pumps air into the waterstripping reservoir 9050 via an air line 9025; a pressure in the waterstripping reservoir 9050 may be about atmospheric pressure. The airpumped by the air compressor or air pump 1100 into the water strippingreservoir 9050 bubbles through the water contained in the waterstripping reservoir 9050 and strips hydrogen sulfide therefrom; this aircan then be vented outside the system, either to the environment or tofurther processing units downstream. Water from the water strippingreservoir 9050, now having been stripped of hydrogen sulfide, thentravels to the high-pressure low-volume pump 9150 via connection 9100.The relief regulator 9200 is connected to the high-pressure low-volumepump 9150 and vents fluid as necessary to maintain a pressure in thehigh-pressure low-volume pump 9150 at or below a selected setpoint; byway of non-limiting example, the setpoint may be approximately equal tothe maximum allowable operating pressure (MAOP) of the pressurized oilsample container 9300 and/or of the water sample container 9400, e.g.about 2000 psi. The water from the high-pressure low-volume pump 9150then travels to the pressurized oil sample container 9300 via connection9250; a pressure in the pressurized oil sample container 9300 may beabout 75 psi. The water that travels from the high-pressure low-volumepump 9150 into the pressurized oil sample container 9300 via connection9250 passes through the pressurized oil sample container 9300 and in sodoing strips hydrogen sulfide from oil contained in the pressurized oilsample container 9300, then passes to the separate water samplecontainer 9400 via element 9350. The water then passes from the watersample container 9400 back to the water stripping reservoir 9050. Aliquid pressure regulator 9500 may be connected to the line connectingthe water sample container 9400 to the water stripping reservoir 9050and may be configured to maintain a pressure in the line at or below aselected setpoint; by way of non-limiting example, the setpoint may beabout equal to the pressure in the pressurized oil sample container9300, e.g. about 75 psi.

In one embodiment, the system 1 and/or first subsystem 2 and/or secondsubsystem 3 further comprises: the addition of an electric field toincrease efficiency and/or effectiveness of hydrogen sulfide and/orsulfur removal, and the addition of the high intensity acoustic wavesand resulting cavitation to increase efficiency and/or effectiveness ofhydrogen sulfide and/or sulfur removal.

In other embodiments, the system 1 and/or first subsystem 2 and/orsecond subsystem 3 is performed on-board a sea-borne vesselcarrying/shipping sour oil (to include a cruise ship), aboard railcars,within pipelines, in concert with traditional refinery operations (toinclude H₂S generated from refining processes comprising hydrocracking,hydrolysis, elemental sulfur production).

In one embodiment, the process of FIG. 1 is used wherein bunker oil isfirst processed as above to remove sulfur, and then the process of FIG.3 is used to remove hydrogen sulfide from the treated bunker oil. In oneembodiment, the input oil to system is refined oil. In one embodiment,the first subsystem 2 first liberates sulfur from bunker oil, and thesecond subsystem 3 removes hydrogen sulfide. In one embodiment, theremoval of hydrogen sulfide is accomplished without aid of specialchemicals, such as catalyst chemicals, scavenger chemicals, hydrocarbonsources, and without the use of traditional large-scale facilities. Inone embodiment, the removal of hydrogen sulfide is accomplished with theaid of an electric current.

These and other advantages will be apparent from the disclosure of theinvention(s) contained herein. The above-described embodiments,objectives, and configurations are neither complete nor exhaustive. Aswill be appreciated, other embodiments of the invention are possibleusing, alone or in combination, one or more of the features set forthabove or described in detail below. Further, this Summary is neitherintended nor should it be construed as being representative of the fullextent and scope of the present invention. The present invention is setforth in various levels of detail in this Summary, as well as in theattached drawings and the detailed description below, and no limitationas to the scope of the present invention is intended to either theinclusion or non-inclusion of elements, components, etc. in thisSummary. Additional aspects of the present invention will become morereadily apparent from the detailed description, particularly when takentogether with the drawings, and the exemplary claim provided herein.

1. A method for removing hydrogen sulfide from sour water, comprising:a) treating a first H.sub.2S water to remove a portion of hydrogensulfide contained therein by bubbling air up through the first H.sub.2Swater, thereby generating an amount of a second H.sub.2S water havingless hydrogen sulfide than the first H.sub.2S water; b) collecting theair after it has bubbled through the first H.sub.2S water, the collectedair comprising hydrogen sulfide; c) mixing the collected air with astream of air to form an air mixture that contains a lower concentrationof hydrogen sulfide than the collected air; and d) combining the secondH.sub.2S water with the first H.sub.2S water, e) maintaining the pH ofat least one of the first H.sub.2S water and the second H.sub.2S waterat no more than about 7.0, and f) venting the air mixture to theenvironment; and wherein steps a) through d) are repeated until anamount of hydrogen sulfide in the first H.sub.2S water is below apredetermined amount and measuring an amount of hydrogen sulfide in thecollected air, and wherein hydrogen sulfide is removed from the sourwater without the use of catalyst chemicals or scavenger chemicals. 2.The method of claim 1, further comprising measuring an amount ofhydrogen sulfide in the second H.sub.2S water.
 3. The method of claim 1,wherein the method is carried out under atmospheric pressure.
 4. Themethod of claim 1, wherein a temperature of the sour water is above 45degrees Fahrenheit.
 5. The method of claim 1, wherein the sour water istreated at an exploratory site.
 6. The method of claim 1, wherein thesour water is not heated to a temperature above 110 degrees Fahrenheit.7. The method of claim 1, wherein the sour water contains hydrogensulfide in an amount greater than 100 ppm.
 8. A method for removinghydrogen sulfide from sour water, comprising: a) treating a firstH.sub.2S water to remove a portion of hydrogen sulfide contained thereinby bubbling air up through the first H.sub.2S water, thereby generatingan amount of a second H.sub.2S water having less hydrogen sulfide thanthe first H.sub.2S water; b) collecting the air after it has bubbledthrough the first H.sub.2S water, the collected air comprising hydrogensulfide; c) measuring an amount of hydrogen sulfide in the collectedair; d) mixing the collected air with a stream of air to form an airmixture that contains a lower concentration of hydrogen sulfide than thecollected air; and e) combining the second H.sub.2S water with the firstH.sub.2S water, f) venting the air mixture to the environment; g)measuring an amount of hydrogen sulfide in the second H.sub.2S water;wherein steps a) through e) are repeated until an amount of hydrogensulfide in the first H.sub.2S water is below a predetermined amount;maintaining the pH of at least one of the first H.sub.2S water and thesecond H.sub.2S water at no more than about 7.0; and wherein the methodis carried out under atmospheric pressure, and wherein hydrogen sulfideis removed from the sour water without the use of catalyst chemicals orscavenger chemicals.
 9. The method of claim 8, wherein the sour watercontains hydrogen sulfide in an amount greater than 100 ppm.
 10. Themethod of claim 8, wherein a temperature of the sour water is above 45degrees Fahrenheit.
 11. The method of claim 8, wherein the sour water istreated at an exploratory site.
 12. The method of claim 8, wherein thesour water is not heated to a temperature above 110 degrees Fahrenheit.13. The method of claim 8, further comprising venting the air mixture tothe environment.
 14. A method for removing hydrogen sulfide from sourwater, comprising: a) treating a first H.sub.2S water to remove aportion of hydrogen sulfide contained therein by bubbling air up throughthe first H.sub.2S water, thereby generating an amount of a secondH.sub.2S water having less hydrogen sulfide than the first H.sub.2Swater; b) collecting the air after it has bubbled through the firstH.sub.2S water, the collected air comprising hydrogen sulfide; c) mixingthe collected air with a stream of air to form an air mixture thatcontains a lower concentration of hydrogen sulfide than the collectedair; and d) combining the second H.sub.2S water with the first H.sub.2Swater, e) venting the air mixture to the environment; f) measuring anamount of hydrogen sulfide in the second H.sub.2S water, and g)measuring an amount of hydrogen sulfide in the collected air, whereinsteps a) through d) are repeated until an amount of hydrogen sulfide inthe first H.sub.2S water is below a predetermined amount; whereinhydrogen sulfide is removed from the sour water without the use ofcatalyst chemicals or scavenger chemicals; wherein a temperature of thesour water is above 45 degrees Fahrenheit, and wherein the sour water istreated at an exploratory site.
 15. The method of claim 14, furthercomprising maintaining the pH of at least one of the first H.sub.2Swater and the second H.sub.2S water at no more than about 7.0.
 16. Themethod of claim 14, wherein the method is carried out under atmosphericpressure.
 17. The method of claim 14, wherein the sour water is notheated to a temperature above 110 degrees Fahrenheit.
 18. The method ofclaim 14, further comprising venting the air mixture to the environment.19. The method of claim 14, further comprising measuring an amount ofhydrogen sulfide in the second H.sub.2S water
 20. The method of claim14, wherein the sour water contains hydrogen sulfide in an amountgreater than 100 ppm.